10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-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, 2022
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _________ to  ___________

Commission File Number	Exact Name of Registrant as Specified In Its Charter	State or Other Jurisdiction of Incorporation or Organization	IRS Employer Identification Number
1-12609	PG&E CORPORATION	California	94-3234914
1-2348	PACIFIC GAS AND ELECTRIC COMPANY	California	94-0742640

300 Lakeside Drive				300 Lakeside Drive
Oakland,	California		94612	Oakland,	California		94612
(Address of principal executive offices) (Zip Code)				(Address of principal executive offices) (Zip Code)
	415	973-1000			415	973-1000
(Registrant’s telephone number, including area code)				(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, no par value	PCG	The New York Stock Exchange
Equity Units	PCGU	The New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 6% nonredeemable	PCG-PA	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable	PCG-PB	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemable	PCG-PC	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemable	PCG-PD	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% series A redeemable	PCG-PE	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemable	PCG-PG	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemable	PCG-PH	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable	PCG-PI	NYSE American LLC

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation:	☒	Yes	☐	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 Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation			Pacific Gas and Electric Company
	☒	Large accelerated filer		☐	Large accelerated filer
	☐	Non-accelerated filer		☒	Non-accelerated filer
	☐	Smaller reporting company		☐	Smaller reporting company
	☐	Accelerated filer		☐	Accelerated filer
	☐	Emerging growth company		☐	Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PG&E Corporation:	☐
Pacific Gas and Electric Company:	☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
PG&E Corporation:	☒
Pacific Gas and Electric Company:	☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
PG&E Corporation:	☐
Pacific Gas and Electric Company:	☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
PG&E Corporation:	☐
Pacific Gas and Electric 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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
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 June 30, 2022, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock	$20,819 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 16, 2023:
PG&E Corporation:	2,466,208,388*
Pacific Gas and Electric Company:	264,374,809
*Includes 187,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 290,000,000 shares of common stock held by Pacific Gas and Electric Company.

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 2023 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

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Contents

CRITICAL ACCOUNTING ESTIMATES

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NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 5: DEBT

NOTE 6: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

NOTE 7: COMMON STOCK AND SHARE-BASED COMPENSATION

NOTE 8: PREFERRED STOCK

NOTE 9: EARNINGS PER SHARE

NOTE 10: INCOME TAXES

NOTE 11: DERIVATIVES

NOTE 12: FAIR VALUE MEASUREMENTS

NOTE 13: EMPLOYEE BENEFIT PLANS

NOTE 14: RELATED PARTY AGREEMENTS AND TRANSACTIONS

NOTE 15: WILDFIRE-RELATED CONTINGENCIES

NOTE 16: OTHER CONTINGENCIES AND COMMITMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 34)

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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.

2022 Form 10-K	PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2022
2021 Form 10-K	PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2021
AB	Assembly Bill
AFUDC	allowance for funds used during construction
Amended Articles	Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022
ARO	asset retirement obligation
ASU	accounting standard update issued by the Financial Accounting Standards Board
Bankruptcy Code	the United States Bankruptcy Code
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
CAPP	California Arrearage Payment Program
CARB	California Air Resources Board
CARE	California Alternate Rates for Energy Program
CCA	Community Choice Aggregator
CCPA	California Consumer Privacy Act of 2018
CEC	California Energy Resources Conservation and Development Commission
CEMA	Catastrophic Event Memorandum Account
Chapter 11	Chapter 11 of Title 11 of the U.S. Code
Chapter 11 Cases	the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Order	the order confirming the Plan, dated as of June 20, 2020, with the Bankruptcy Court
Corporation Revolving Credit Agreement	Credit Agreement, dated as of July 1, 2020, as amended, by and among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent
CHT	Customer Harm Threshold
CPIM	Core Procurement Incentive Mechanism
CPPMA	COVID-19 Pandemic Protections Memorandum Account
CPUC	California Public Utilities Commission
CRR	congestion revenue rights
CVA	climate vulnerability assessment
D&O Insurance	directors’ and officers’ liability insurance
DA	Direct Access
Diablo Canyon	Diablo Canyon nuclear power plant
District Court	United States District Court for the Northern District of California
DOE	United States Department of Energy
DOJ	United States Department of Justice
DTA	deferred tax asset
DTSC	California Department of Toxic Substances Control
DWR	California Department of Water Resources
EMANI	European Mutual Association for Nuclear Insurance
Emergence Date	July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEP	Enhanced Oversight and Enforcement Process

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EPA	U.S. Environmental Protection Agency
EPS	earnings per common share
EPSS	Enhanced Powerline Safety Settings
EVM	enhanced vegetation management
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
FHPMA	Fire Hazard Prevention Memorandum Account
Fire Victim Trust	The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be, funded
First Mortgage Bonds	bonds issued pursuant to the Indenture of Mortgage, dated as of June 19, 2020 between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GO	general order
GRC	general rate case
GT&S	gas transmission and storage
HFTD	high fire threat district
HSMA	Hazardous Substance Memorandum Account
IRC	Internal Revenue Code of 1986, as amended
IOUs	investor-owned utility(ies)
Kincade Amended Complaint	The amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Lakeside Building	300 Lakeside Drive, Oakland, California, 94612
LSEs	load serving entities
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
MGMA	Microgrids Memorandum Account
MGP	manufactured gas plants
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceeding
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
New Shares	Shares of PG&E Corporation common stock held by ShareCo that may be exchanged for Plan Shares as contemplated by the Share Exchange and Tax Matters Agreement
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OEIS	Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OII	order instituting investigation
OIR	order instituting rulemaking
Pacific Generation	Pacific Generation LLC, a subsidiary of the Utility
PCAOB	Public Company Accounting Oversight Board (United States)
PD	proposed decision
PERA	Public Employees Retirement Association
Plan	PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
Plan Shares	Shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan

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PSPS	Public Safety Power Shutoff
QF	Qualifying facilities
RA	Resource Adequacy
Receivables Securitization Program	The accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility’s accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROE	return on equity
ROU asset	right-of-use asset
RPS	Renewables Portfolio Standard
RTBA	Risk Transfer Balancing Account
RUBA	Residential Uncollectibles Balancing Account
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
SED	Safety and Enforcement Division of the CPUC
SFGO	The Utility’s San Francisco General Office headquarters complex
Share Exchange and Tax Matters Agreement	Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust
ShareCo	PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV	PG&E AR Facility, LLC
Tax Act	Tax Cuts and Jobs Act of 2017
TO	transmission owner
TURN	The Utility Reform Network
USFS	United States Forest Service
Utility	Pacific Gas and Electric Company
Utility Revolving Credit Agreement	Credit Agreement, dated as of July 1, 2020, as amended, by and among the Utility, the several banks and other financial institutions or entities party thereto from time to time and Citibank, N.A., as Administrative Agent and Designated Agent
VIE(s)	variable interest entity(ies)
VMBA	Vegetation Management Balancing Account
VSP	voluntary separation program
WEMA	Wildfire Expense Memorandum Account
Wildfire Fund	statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WMBA	Wildfire Mitigation Balancing Account
WMCE	Wildfire Mitigation and Catastrophic Events
WMP	wildfire mitigation plan
WMPMA	Wildfire Mitigation Plan Memorandum Account

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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 that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, 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,” “commit,” “goal,” “target,” “will,” “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 extent to which the Wildfire Fund and revised prudency standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires, including whether the Utility maintains an approved WMP and a valid safety certification and whether the Wildfire Fund has sufficient remaining funds;

•the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service area, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), the wildfire that began on September 6, 2022 near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), and any other wildfires for which the causes have yet to be determined; the damage caused by such wildfires; the extent of the Utility’s liability in connection with such wildfires (including the risk that the Utility may be found liable for damages regardless of fault); investigations into such wildfires, including those being conducted by the CPUC; the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire; potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action in respect of any such fire; the risk that the Utility is not able to recover costs from the Wildfire Fund or other third parties or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations, and proceedings;

•the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; or to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; the cost of the program and the timing and outcome of any proceeding to recover such costs through rates; and any determination by OEIS that the Utility has not complied with its WMP;

•the impact of the Utility’s implementation of its PSPS program, and whether any fines, penalties, or civil liability for damages will be imposed on the Utility as a result; the costs in connection with PSPS events, the timing and outcome of any proceeding to recover such costs through rates, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

•the Utility’s ability to safely, reliably, and efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably;

•significant changes to the electric power and gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs, DA providers, and legislative mandates to replace gas-fuel technologies; and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources and changing customer demand for its natural gas and electric services;

•cyber or physical attacks, including acts of terrorism, war, and vandalism, on the Utility or its third-party vendors, contractors, or customers (or others with whom they have shared data) which could result in operational disruption; the misappropriation or loss of confidential or proprietary assets, information or data, including customer, employee, financial, or operating system information, or intellectual property; corruption of data; or potential costs, lost revenues, litigation, or reputational harm incurred in connection therewith;

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•the impact of severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, 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, and the effectiveness of the Utility’s efforts to prevent, mitigate, or respond to such conditions or events; the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

•existing and future regulation and federal, state or local legislation, their implementation, and their interpretation; the cost to comply with such regulation and legislation; and the extent to which the Utility recovers its associated compliance and investment costs, including those regarding:

◦wildfires, including inverse condemnation reform, wildfire insurance, and additional wildfire mitigation measures or other reforms targeted at the Utility or its industry;

◦the environment, including the costs incurred to discharge the Utility’s remediation obligations or the costs to comply with standards for GHG emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and electric vehicles;

◦the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, and cooling water intake, and whether Diablo Canyon’s operations are extended; and the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

◦the regulation of utilities and their affiliates, including the conditions that apply to PG&E Corporation as the Utility’s holding company;

◦privacy and cyber security; and

◦taxes and tax audits;

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; the Utility’s application to transfer its non-nuclear generation assets to Pacific Generation and the potential sale of a minority interest in Pacific Generation; and the transfer of ownership of the Utility’s assets to municipalities or other public entities, including as a result of the City and County of San Francisco’s valuation petition;

•whether the Utility can control its operating costs within the authorized levels of spending; whether the Utility can continue implementing the Lean operating system and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the risks and uncertainties associated with inflation; 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 outcome of current and future self-reports, investigations or other enforcement actions, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cyber security protections; environmental laws and regulations; or otherwise, such as fines; penalties; remediation obligations; or the implementation of corporate governance, operational or other changes in connection with the EOEP;

•the risks and uncertainties associated with PG&E Corporation’s and the Utility’s substantial indebtedness and the limitations on their operating flexibility in the documents governing that indebtedness;

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•the risks and uncertainties associated with the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including appeals of the Confirmation Order; certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; three purported class actions that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•the ability of PG&E Corporation and the Utility to securitize the remaining $1.385 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility;

•the risks and uncertainties associated with any future substantial sales of shares of common stock of PG&E Corporation by existing shareholders, including the Fire Victim Trust;

•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the IRC, as a result of which tax attributes could be limited;

•PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases and the financial and other restructuring undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;

•the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

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

•the risks and uncertainties associated with rising rates for the Utility’s customers;

•actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings;

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on energy demand in the Utility’s service area, the ability of the Utility to collect on customer receivables, the ability of the Utility to mitigate these effects, including with spending reductions, the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions caused either by illness of workers and their family members or workforce attrition related to potential new workplace regulations such as vaccine mandates; 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, liquidity, and cash flows, see Item 1A. Risk Factors in this Form 10-K and a detailed discussion of these matters contained in Item 7. 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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PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-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 principal 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. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors, including regarding dividends, at http://investor.pgecorp.com, under the “Wildfire and Safety Updates,” “News & Events: Events & Presentations,” and “Shareholders: Dividend Information” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident to the CPUC. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link. PG&E Corporation and the Utility also make available to investors information about the companies’ climate goals and progress in the Corporate Sustainability Report and Climate Strategy Report, which information is not incorporated by reference into this report.

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. The Utility’s service area is shown in the graphic below.

PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below in Item 8. Financial Statements and Supplementary Data.

The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules, and regulations.

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Over the past several years, Northern California has experienced major wildfires. For more information about material wildfires, see Item 7. MD&A, and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

This 2022 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, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors and “Forward-Looking Statements” above.

Triple Bottom Line

PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the difficulties many coworkers face in their day-to-day work, and deliver better outcomes for customers and communities.

PG&E Corporation and the Utility measure their progress toward the purpose by considering their impact on the “triple bottom line” of people, planet, and prosperity, which is underpinned by performance; this consideration takes into account not only the economic value they create for customers and investors, but also their responsibility to social and environmental goals. The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities.

PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions. The Utility will continue to seek fair and timely regulatory treatment in order to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world class performance while delivering hometown service.

People

The people element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders.

PG&E Corporation’s and the Utility’s goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe. Their focus is on continuously building an organization where every work activity is designed to facilitate safe performance, every worker knows and practices safe behaviors, and every individual is encouraged to speak up and stop work if they see unsafe or risky behavior, and has confidence that their concerns and ideas will be heard and pursued. PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction.

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitably-paid workforce. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas reliability, and improving customer satisfaction.

For more information, see “Human Capital” below.

Planet

The planet element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations. PG&E Corporation and the Utility believe that integrating and managing climate change and other environmental considerations in the companies’ business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, coworkers, and other stakeholders. Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility’s business and economic opportunity for the communities it serves.

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The Utility strives to be prepared to continue to deliver safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards. To build resilience to these hazards, the Utility is working to systematically integrate the consideration of forward-looking climate data and tools in its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate adaptation policy in California, and work directly with local governments and communities on adaptation solutions.

PG&E Corporation and the Utility have committed to helping heal the planet. PG&E Corporation’s and the Utility’s Climate Strategy Report, which is available to the public, describes the companies’ climate goals and plans to meet those goals. To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the electric system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased penetration of renewable energy combined with investments in the grid and energy storage.

PG&E Corporation and the Utility also plan to transition the gas system to cleaner fuels, increasingly target natural gas delivery for hard-to-electrify customer sectors, and support efforts to accelerate building electrification. The objective is to do so in an orderly manner to achieve a positive customer and community experience, while reducing natural gas system investments in targeted electrified communities.

The impacts of climate change on the Utility’s infrastructure are already a reality. Record-breaking extreme heat and heat waves are increasingly a regular occurrence throughout California. Peak electric loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage, and increasingly driven in the future from widespread progress in adoption of beneficial electrification technologies. The Utility’s assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise.

Climate change will also continue to intensify the potential for wildfires throughout California. The worsening conditions across California increase the likelihood and severity of wildfires, including those where the Utility’s equipment may be alleged to be associated with the fire’s ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility. A key element of preparing the Utility for the physical risks of climate change is an updated and more detailed system-wide CVA of the Utility’s assets, operations, and services, which the Utility expects to file with the CPUC in 2024. The CVA is expected to improve the Utility’s understanding of its exposure to climate hazards and the sensitivity of assets and operations to these hazards.

PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, and affordable clean and resilient energy for their customers. As a result of actions already taken by PG&E Corporation and the Utility, the companies have:

•Delivered clean electricity to customers in 2022 that was more than 95% GHG free.

•Helped customers avoid emissions and energy costs through robust energy efficiency programs.

•Awarded contracts for more than 3.3 GWs of battery energy storage to be deployed over the next several years, strengthening California’s grid efficiency and reliability.

•Installed approximately 340 charging ports for electric vehicles at schools, parks, public charging locations, and in support of fleets - with nearly half in disadvantaged communities - and received regulatory approval for new innovative pilots on vehicle grid integration, submetering, and dynamic rates.

•Brought the total number of interconnected private solar customers to more than 700,000 and supported more than 50,000 customers who have installed battery storage at their homes or businesses.

•Continued to advance decarbonization initiatives for the Utility’s natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule and accelerating initiatives to meet its voluntary 2030 reduction goal.

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The CPUC coordinates the planning of supply resources through the Integrated Resource Planning (“IRP”) proceeding and has determined that replacing the power generated by Diablo Canyon is the responsibility of all LSEs within the CAISO. Looking ahead, the Utility expects its GHG-free energy supply mix of renewable, large hydroelectric, and nuclear generation resources to decrease as, beginning in 2023, the Utility is required to offer for allocation or sale renewables portfolio standard-eligible (“RPS”) attributes that the Utility procured on behalf of customers that subsequently switched to non-Utility providers in order to comply with regulatory mandates and to manage customer affordability. Towards the end of the decade and beyond, the Utility’s GHG-free energy supply mix is expected to grow relative to 2025 levels as the Utility procures new GHG-free generation and storage to meet California’s IRP GHG emissions reduction targets and California’s clean energy goals. For more information, see “Electric Integrated Resource Planning and Related Procurement” below.

Prosperity

The prosperity element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to meeting their financial objectives and providing economic development opportunities and benefits in the communities they serve. Management believes clean energy should be affordable for and inclusive of all economic backgrounds.

Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs.

See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.

Generally, differences between forecast costs and actual costs (discussed in “Utility Revenues and Costs that Impacted Earnings” in Results of Operations in Item 7. MD&A) 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.

PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing their debt. PG&E Corporation and the Utility have set goals to reduce their debt over time, including reducing PG&E Corporation’s debt by at least $2 billion by the end of 2026. PG&E Corporation and the Utility expect that reducing the consolidated debt will help them achieve investment grade credit ratings for their unsecured securities, for the benefit of both customers and investors. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8. Pursuant to SB 901, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs, which was approved by the CPUC on February 28, 2022. PG&E Wildfire Recovery Funding LLC, a bankruptcy remote, limited liability company wholly owned by the Utility, issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. The net proceeds from both transactions were used to reimburse the Utility for previously incurred recovery costs, including the retirement of $5.0 billion of Utility debt and the repayment of a portion of the loans outstanding under the Utility's revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility intends to use a portion of the remaining proceeds to fund the redemption of $1.0 billion of Utility debt. For more information, see “Application for Post-Emergence Securitization Transaction” in Item 7. MD&A.

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, as well as the Utility’s preferred stock. PG&E Corporation’s and the Utility’s ability to issue dividends is subject to restrictions. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock. On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility’s common stock. For more information, see “Dividends” in Item 7. MD&A.

Total capital expenditures (including accruals) recorded in 2022 were $9.6 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be between $7.9 billion and $11.2 billion for 2023, between $7.9 billion and $12.2 billion for 2024, between $8.0 billion and $12.7 billion for 2025, between $8.1 billion and $13.3 billion for 2026, and between $8.1 billion and $13.8 billion for 2027. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather, and other unforeseen conditions.

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The Utility expects to make additional capital expenditures, the recovery of which will be subject to future regulatory approval, including the 2023 GRC. These expenditures include capital expenditures exceeding amounts authorized in the 2020 GRC and 2019 GT&S, and expenditures to be included in a later stage of the 2023 GRC or separate applications. These expenditures are expected to primarily be for wildfire mitigation, transportation electrification, and the Lakeside Building. Additionally, $3.21 billion of fire risk mitigation capital expenditures will be excluded from the Utility’s equity rate base pursuant to AB 1054.

PG&E Corporation and the Utility are committed to keeping gas and electric services affordable for all customers. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements collectively place continuing upward pressure on customer rates. Certain CPUC proceedings could impact different types of customers differently. Similarly, although the Utility generally recovers its electricity and natural gas procurement costs through rates as “pass-through” costs, commodity prices rose substantially in 2022, relative to 2021. The Utility has set a goal to increase customer capital investments while also limiting customer impacts, including by reducing non-fuel Operating and maintenance costs by two percent per year and by seeking efficient financing. The Utility plans to meet its two percent non-fuel Operating and maintenance cost reduction goal through increased efficiency, including waste elimination through the Lean operating system. The Utility has a number of programs in place to assist low-income customers, such as the CARE program. Under the CARE program, income-qualified customers can receive a monthly discount of 20% or more on their gas and electric bill.

PG&E Corporation’s and the Utility’s Corporate Sustainability Report, which is available to the public, describes the companies’ progress toward world-class performance measured with the triple bottom line framework.

In 2021, the Utility spent $4.01 billion with certified diverse suppliers, representing 38.7% of its total spend.

Performance: Underpinning the Triple Bottom Line

PG&E Corporation and the Utility use the Lean operating system, which includes four basic “plays:” visual management; operating reviews; problem solving; and standard work. Visual management allows teams to see how they are performing against their most important metrics using real-time data. PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of workers closest to the work with the goals and objectives of senior leadership. These brief meetings help the Utility identify gaps and quickly develop plans to support the teams performing the work and give the Utility more visibility, control and predictability in its operations. Problem solving involves a structured approach to identifying, containing, analyzing, and solving problems in order to capitalize on opportunities. Standard work reduces costs and increases productivity by ensuring a consistent company-wide method for completing a task. For instance, the Lean operating system helped the Utility identify patterns in the conditions of ignitions and led to the implementation of EPSS and drove significant benefit and understanding in how PG&E Corporation and the Utility manage customer satisfaction. PG&E Corporation’s and the Utility’s performance is also driven by an increased focus on alignment on shared outcomes among its leadership and within the organization. In 2023, PG&E Corporation’s and the Utility’s Lean deployment will focus on a fifth play, waste elimination, which enables the companies to identify and eliminate inefficiencies in both process and workflow in a sustainable manner, as well as the continued adoption of a performance playbook and improvements to financial visibility and controls.

PG&E Corporation and the Utility have implemented a regional service model to bring the Utility closer to the hometowns it serves. Through the regional service model, the Utility has restructured its service area into five regions, with leaders in each region to deliver improved public and employee safety, customer service, and operational reliability outcomes.

PG&E Corporation and the Utility are committed to designing an electric system that is resilient to climate change, decarbonized, and optimized to local and system needs.

California has experienced unprecedented weather conditions in recent years and the Utility’s service area remains susceptible to additional wildfire activity. In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including:

•Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them more rapidly in the event of a disturbance to help prevent potential ignitions. After EPSS was initiated, both the size and number of CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average.

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•Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions. Since its inception in late 2017, the PSPS program has become more targeted because the Utility has developed more granular risk models, including adding consideration of vegetation management and maintenance tag statuses for scoping PSPS events. The Utility has also installed sectionalizers for more targeted de-energizations of circuits and transmission lines. In 2022, the Utility did not have any PSPS events.

•Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and clear vegetation that might grow or fall into utility equipment. The Utility is also increasing oversight and engagement with the contractors supporting vegetation management work.

•Asset inspections: Since 2018, the Utility has reoriented its asset inspections programs toward asset condition and consequence risk, particularly wildfire risk, and these programs have become more thorough, standardized, digitized, and verifiable. The Utility uses risk-informed inspection cycles. In 2022, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections. As a result of the improved inspection program, the Utility’s inspections in recent years have begun to more thoroughly identify equipment conditions.

•System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTDs and installing stronger and more resilient equipment. As the Utility’s asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions than in prior years. Hardening methods include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground. In 2021, the Utility announced a program to underground 10,000 miles of electric distribution lines in high wildfire risk areas. In 2022, the Utility undergrounded 180 miles of lines, which exceeded its plan to underground 175 miles of lines. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. The Utility also brought online two additional “remote grids” in 2022, which allow distribution lines in HFTDs to be removed and replaced with locally sited resources. Remote grids can reduce costs and fire risks, while maintaining service to participating customers.

As a result of these measures, the Utility significantly reduced both the size and number of CPUC-reportable ignitions and number of acres burned in 2022, compared to prior years.

Even as the Utility works to mitigate wildfire risk, it also works to reduce the impact of those mitigations on its customers, including making the PSPS program less disruptive through sectionalizing devices for both distribution and transmission lines, temporary generation applications, and implementation of microgrids which enable portions of the grid to safely isolate areas from the broader grid and energize them during outages. For example, in 2022, the Utility prepared 12 distribution microgrids to operate with temporary generation if needed.

In 2022, the Utility expanded the EPSS program to all high fire risk areas. In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for maximum wildfire ignition risk reduction when needed and enhancing reliability benefits when wildfire risk is low. In 2022, the Utility also began reviewing and adjusting settings to improve coordination among devices on a circuit to reduce the number of customers impacted by an outage. In 2023, the Utility will expand its deployment of advanced technology to detect low-current faults, which is expected to further decrease wildfire ignition risk.

PG&E Corporation and the Utility are continuing to invest in a safe and reliable gas system and are working toward targeted electrification, greening the gas supply, and shaping California energy policy. The Utility has focused on continuously improving its gas operations safety record. Since the San Bruno natural gas pipeline explosion in 2010, the Utility’s asset safety efforts have included replacing distribution mains and transmission pipelines, as well as strength testing transmission pipelines. The Utility uses in-line inspections to assess the integrity of transmission pipelines. The Utility also uses safety and control systems to monitor, gather, and process real-time data on its gas system. In 2022, the Utility’s gas operations had two workforce serious injuries and fatalities (“SIF-A”) incidents and reductions in the number of injuries that result in days away, restricted or transferred duty per 200,000 hours worked (“DART”). The Utility’s gas system has not had a safety-related incident that affected the public and resulted in a fatality or injury since 2015 or 2018, respectively.

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The Utility has engaged in educating employees, contractors, and the public regarding safe digging programs and practices for their awareness during construction and when digging near the Utility’s underground gas and electric assets. The Utility also installed safety devices that automatically detect increasing pressure on systems and stop the flow of gas to avoid outages and overpressure events. Additionally, the Utility continues to streamline its efforts to respond to outages on a timely basis. The Utility’s outage response is designed to keep the public safe while limiting customer outages and returning service safely and as quickly as possible.

The Utility’s generation operations have focused on safety and reliability. In 2022, the Utility’s nuclear and non-nuclear generation operations achieved zero SIF-A incidents and reductions in DART. Challenged by a drought year, the Utility scheduled dispatch and rescheduled outages to maximize availability during the summer months when demand for electricity is highest. The Utility is working to implement a comprehensive non-nuclear generation asset management strategy and further mature its outage and project management capabilities.

In 2022, the Utility achieved International Organization for Standardization (“ISO”) 55001 certification for its electric operations and generation asset management systems. The Utility also achieved ISO 55001 re-certification for its gas operations asset management. ISO 55001 certification required the Utility to demonstrate that it has policies and procedures to manage its assets responsibly and effectively.

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 regulated primarily by the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and OEIS.

This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. For more information, see Item 1A. Risk Factors and “Regulatory Matters” in Item 7. MD&A.

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.

California Public Utilities Commission

The CPUC is a regulatory agency that regulates privately owned public utilities in California. 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 has also exercised jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electric and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

The CPUC enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities.  The CPUC can impose penalties of up to $100,000 per day, per violation. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations, the type of harm caused by the violations and the number of persons affected, and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC 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 the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation; but if it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued. Similar to penalties imposed by the CPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and may not be recovered in rates or otherwise directly or indirectly charged to customers. The CPUC has also authorized the SED to propose for CPUC approval administrative consent orders and administrative enforcement orders when the SED deems a formal OII unnecessary.

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The California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to wildfires and wildfire cost recovery, 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 on specific CPUC enforcement matters and CPUC-implemented laws and policies and the related impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Federal Energy Regulatory Commission and California Independent System Operator Corporation

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 systems and generation facilities, the tariffs and conditions of service of regional transmission organizations, and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electric transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. The FERC’s approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property. The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. For more information on specific FERC requirements and their impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

The CAISO is the FERC-approved regional transmission organization for the Utility’s service area. The CAISO controls the operation of the electric transmission system in most of California and a small part of Nevada and provides open access transmission service on a non-discriminatory basis. The CAISO is also responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generating capacity, ensuring that the reliability of the transmission system is maintained, and operating the wholesale power market in most of California and an interstate energy imbalance market.

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 Item 1A. Risk Factors and Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Other Regulators

The CEC is California’s primary energy policy and planning agency. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans and 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 also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See “Environmental Regulation - Air Quality and Climate Change” below.

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The NTSB is an independent U.S. government investigative agency responsible for civil transportation accident investigations, including pipeline accidents. The NTSB also conducts special investigations and safety studies, and issues safety recommendations to prevent future accidents.

The California Geologic Energy Management Division is the state agency responsible for establishing and enforcing regulations for the operation of the Utility’s underground gas storage facilities.

The OEIS is a state agency responsible for reviewing and approving the Utility’s WMP and for evaluating the Utility’s implementation of the WMP. The OEIS is also responsible for reviewing and issuing the Utility’s annual safety certification, annually reviewing and approving the Utility’s executive compensation plan, conducting assessments of the Utility’s safety culture, and conducting field inspections of wildfire mitigation activities.

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 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. For more information see Item 1A. Risk Factors.

Material Effects of Compliance with Governmental Regulations

As indicated above, the Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. Compliance with such extensive government regulations requires substantial expenditures and has had in the past and may continue to have in the future a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position. For more information about costs incurred to comply with government regulations and related material effects on PG&E Corporation and the Utility, see Item 1A. Risk Factors, “Regulatory Matters” in Item 7. MD&A, and Notes 15 and 16 of the Notes to the Consolidated Financial Statements in Item 8.

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 CO2 and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. See Item 1A. Risk Factors. Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through 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 16 of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Substance Compliance and Remediation

The Utility’s facilities are subject to various regulations adopted by the EPA, including the 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.

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The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the DTSC, 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 MGP sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. 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 16 of the Notes to the Consolidated Financial Statements in Item 8.

Air Quality and Climate Change

The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and other emissions.

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.

Tackling the climate crisis is a key priority of the Biden Administration, and the Administration has signaled its intent to use its executive and regulatory authorities to reduce emissions in line with science-based targets. On January 20, 2021, President Biden issued an executive order directing the EPA to consider suspending, revising or rescinding the Trump Administration’s rule for methane emissions from new sources in the oil and gas sector and propose a companion regulation for existing sources, including the transmission, processing and storage segments of the industry. For power plants, the EPA is expected to propose a more stringent GHG standard for existing sources in the wake of challenges to the Trump Administration’s Affordable Clean Energy rule.

State Regulation

California’s Global Warming Solutions Act of 2006 originally provided 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 applies to the electric generation, large industrial, natural gas, petroleum, and transportation sectors. 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 large natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation.

The cap-and-trade program has been extended through 2030. 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. Entities with a compliance obligation can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Complying entities 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 entities’ facilities through CARB-qualified offset projects such as reforestation or biomass projects). The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.

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California law requires that the CARB ensure a 40% reduction in GHGs by 2030 compared to 1990 levels. The California RPS program that requires utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California. California’s RPS targets are 50% by December 31, 2026 and 60% by December 31, 2030, and the State has set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045. In 2022, AB 1279 was signed into law, codifying a statewide goal to achieve economy-wide carbon neutrality by 2045 and to maintain net negative emissions thereafter. Additionally in 2022, SB 1020 established targets that renewable and zero-carbon resources will supply 90% of utilities’ retail sales to customers by 2035 and 95% of retail sales by 2040. The Utility will be an active participant in regulatory proceedings to determine how the state will achieve carbon neutrality. For the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2022, including estimated GHG-free and renewable energy percentages, see “Electric Utility Operations-Electricity Resources” below.

Climate Change Resilience Strategies

Mitigating Greenhouse Gas Emissions

During 2022, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment, consistent with the Utility’s commitment to a healthy environment and carbon neutral-energy system for all Californians.

Adapting to the Physical Impacts of Climate Change

Effectively managing physical climate risk will become increasingly critical as the physical impacts of climate change become increasingly frequent and severe over the coming years in California. The Utility’s climate resilience efforts continue to focus on characterizing and mitigating the physical impacts of climate change to the Utility’s infrastructure, assets, and operations. The Utility is making substantial investments to build a more resilient system that can better withstand extreme weather and related emergencies. For more information on such investments, see “Performance: Underpinning the Triple Bottom Line” above.

The Utility’s preparations for the physical risks of climate change include an updated, more detailed, system‑wide CVA of the Utility’s assets, operations, and services, which will be completed in 2024 and filed with the CPUC. The updated CVA will improve the Utility’s understanding of its exposure to climate hazards in the near- and long-term and the sensitivity of assets and operations to these hazards. It will also inform the Utility’s understanding of the ease or difficulty of various options for adapting to changing conditions.

In the past few years, the Utility’s electric distribution system has experienced multiple major outage-causing events associated with extreme heat events and peak loads. Peak loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage.

The Utility’s assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine (fluvial), and precipitation related (pluvial) flooding because of climate‑driven changes in precipitation and sea level rise. The risk of damage to or interruptions of operations at facilities such as substations is predicted to increase over time due to sea level rise. Electric and gas equipment and safe access for operations must be prepared for these changing conditions.

Changing precipitation dynamics may impact the Utility’s hydroelectric generation. Diminishing future water availability and altered runoff timing during extreme drought poses risks to hydropower generation, operations, and revenue. Also, extreme rain events suggest enhanced risk of hydropower asset damage or failure associated with flooding, which in the worst cases (e.g., uncontrolled water release) may have catastrophic impacts.

Climate change will also continue to intensify the potential for wildfires throughout California. Models incorporating future temperature and precipitation projections suggest that landscape susceptibility to wildfire within the Utility’s service area will continue to increase over time, with an expansion of areas that may become HFTD and an intensification of risk within HFTDs. Climate change may also result in increased potential of lines to cause ignitions or to require PSPS events, as well as the potential for the Utility’s equipment to sustain damage from wildfires of any origin.

The Utility’s updated CVA will be used to inform changes to design and construction standards for equipment and facilities to increase infrastructure resilience to current and future extreme weather conditions. Results from the updated CVA will be incorporated into the Utility’s key risk and planning functions, as well as asset management strategy, to identify priority adaptive actions.

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The Utility is also engaging with CPUC-designated disadvantaged and vulnerable communities throughout the CVA process to ensure that customer perspectives regarding energy system resilience are part of updating the CVA. The Utility is conducting regional community engagement campaigns throughout its service area to understand how some of the most vulnerable communities the Utility serves think about climate hazards and adaptation. This information will help the Utility plan adaptive climate action aligned with customer and community perspectives.

In addition to updating the CVA, the Utility regularly reviews relevant scientific literature regarding climate change to incorporate appropriate information into its operations. For example, based on a recent report about potential major atmospheric river events, the Utility updated and modified its flooding emergency response plan.

The Utility’s commitment to increasing resilience to climate change includes aligning its resources and business strategy with California’s clean energy goals, the Utility’s climate strategy, and advocating for policies and programs that enable safe and reliable energy for the Utility’s customers in light of climate change. For example, 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 will help it adapt to the expected increases in demand for electricity.

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 2021, which is the most recent data available, totaled Scope 1 and 2 emissions of approximately 4.6 million metric tons of CO2 equivalent (MMT CO2e) and Scope 3 emissions of approximately 42 MMT CO2e, the majority of which came from customer natural gas use.

The following table shows the 2021 GHG emissions data the Utility reported to the CARB, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.

Source	Amount (metric tons CO2 equivalent)
Fossil fuel-fired plants (1)	2,485,379
Natural gas compressor stations and storage facilities (2)	322,047
Distribution fugitive natural gas emissions	589,343
Customer natural gas use (3)	41,563,483

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

(2) Includes emissions from compressor stations and storage facilities that are reportable to CARB.

(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.

The Utility utilized the CEC’s Power Source Disclosure program methodology to calculate the CO2 emissions rate associated with the electricity delivered to retail customers in 2021. This resulted in a third-party verified CO2 emissions rate of 99 pounds of CO2 per MWh.

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. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Sustainability Report.

	2021	2020
Total NOx emissions (tons)	139	141
NOx emissions rate (pounds/MWh)	0.01	0.01
Total SO2 emissions (tons)	14	15
SO2 emissions rate (pounds/MWh)	0.001	0.001

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Nuclear Fuel Disposal

Nuclear power plant operations produce gaseous, liquid, and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools, and equipment contaminated through use.

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 DOJ and the Utility executed a settlement agreement that provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  The claim for the period June 1, 2021 through May 31, 2022, totaled approximately $10.5 million and is under review by the DOE.  Amounts reimbursed by DOE are refunded to customers through rates. 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.

Ratemaking Mechanisms

The Utility operates under a “cost-of-service” ratemaking model, which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and to earn a return on invested capital (“cost-of-service ratemaking”). In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecasted basis. Revenue authorized by the CPUC through GRC proceedings is intended to provide the Utility a reasonable opportunity to recover its costs and earn a return on its investments in generation and distribution assets and general plant (also referred to as “rate base”). 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, and financing expenses).

The Utility’s costs of equity and long-term debt are generally approved in the CPUC’s cost of capital proceedings. 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 Item 7. MD&A), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. FERC revenue requirements are set through a FERC-approved formula rate.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. 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 Item 7. MD&A) within its authorized base revenue requirements.

Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads.  Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating.

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.

See “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC proceedings.

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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 related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base. In the past, the CPUC has generally conducted a GRC every three years. Starting with the 2023 GRC, the CPUC now conducts a GRC every four years that includes the Utility’s costs of its gas transmission and storage facilities. 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 authorized for cost increases related to invested capital and inflation. Parties in the Utility’s GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the overall interests of residential customers, as well as numerous intervenors that represent other business, community, customer, environmental, and union interests. For more information about the Utility’s GRC, see “Regulatory Matters - 2023 General Rate Case” in Item 7. 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’s cost of capital proceedings generally take place in a consolidated proceeding with California’s other large investor-owned electric and gas utilities. For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A.

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. In its TO rate cases, the Utility uses a formula rate methodology, which includes an authorized revenue requirement and rate base for a given year but also provides for an annual update of the previous year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate are either collected from or refunded to customers. The FERC-approved formula rate will be effective through December 31, 2023. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates and by the CAISO in its transmission access charges to wholesale customers. For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7. 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.

Program-Specific Memorandum Account and Balancing Account Costs

Periodically, costs arise outside of the CPUC GRC proceedings or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, new programs, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account, and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed reasonable. For instance, these accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. Recovery of the costs tracked in these memorandum accounts in rates requires CPUC authorization in separate proceedings for which the Utility may be unable to predict the outcome. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts. The CPUC may authorize recovery of costs tracked in the balancing accounts on either a “one-way” basis, which typically only allows actual costs to be recovered up to a pre-established cap, or a “two-way” basis, which typically allows actual costs to be recovered, and in some cases subject to further CPUC review. For more information, see “Regulatory Matters - Cost Recovery Proceedings” in Item 7. MD&A and Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

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Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California IOUs are responsible for procuring electrical capacity required to meet bundled customer demand, plus applicable reserve margins. 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 Procurement Plans (“BPPs”) based on long-term demand forecasts. In October 2015, the CPUC approved the Utility’s most recent comprehensive BPP. It has been revised since its initial approval, and the revised version will remain in effect, subject to any further revisions, until superseded by a subsequent CPUC-approved plan.

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved BPPs 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 CPUC may disallow the value of lost generation due to unplanned outages at utility-owned generation facilities.

The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 4 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 electric rates more frequently if the forecasted aggregate over-collections or under-collections in the Energy Resource Recovery Account, net of bundled service customer Portfolio Allocation Balancing Account balances, exceed five percent of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the procurement transactions recovered in various balancing accounts, including the Energy Resource Recovery Account and the Portfolio Allocation Balancing 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 BPP, to meet mandatory renewable energy targets, and to comply with RA requirements. For more information, see “Electric Utility Operations - Electricity Resources” below as well as Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility is also responsible, as the central procurement entity (“CPE”) for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all CPUC-jurisdictional LSEs in its distribution service area. CPUC decisions grant the Utility, acting as CPE, discretion to defer procurement of local resources to the CAISO’s backstop mechanisms if bid costs are deemed unreasonably high. The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, as long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met. In addition, the Utility, as the CPE, has been ordered or authorized to seek to procure specific local capacity products pursuant to CPUC decisions. In connection with its CPE function, the Utility is responsible for making compliance demonstrations to the CPUC and the CAISO. The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account. Each year, the CPUC reviews the Utility’s forecasted administrative costs related to the CPE function and approves a forecasted revenue requirement associated with the administrative costs. The CPUC performs an annual compliance review of the CPE function, including procurement transactions with terms of five years or less (for which costs incurred in compliance with certain prescribed criteria are deemed reasonable and pre-approved without further after-the-fact reasonableness review). Procurement transactions with terms exceeding five years are reviewed separately. The CPUC may disallow costs associated with the CPE function that were not incurred in compliance with the CPUC’s decisions and guidance.

The CPUC has also approved the Power Charge Indifference Adjustment (“PCIA”). The PCIA is a cost recovery mechanism to ensure that customers who switch from the Utility’s bundled service to a non-Utility provider, such as a DA or CCA provider, pay their share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf.

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 electric rates.

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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 CPIM described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rate changes.

The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio. Under the CPIM, the Utility’s natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered through rates. One-half of the costs above 102% of the benchmark are recoverable through 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 the 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 discounted rates for specified types of customers, such as for low-income customers under the CARE program, which is paid for 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 generally 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. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers. Pursuant to Public Utilities Code Section 8325, to the extent the monies available for decommissioning are insufficient to pay for all reasonable and prudent decommissioning costs, the CPUC must authorize the electric utility to collect these charges from its customers.

For costs related to AROs see “Asset Retirement Obligations” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

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Human Capital

Employees and Contractors

As of December 31, 2022, PG&E Corporation had 10 employees and the Utility had approximately 26,000 regular employees. Of the Utility’s regular employees, approximately 16,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”). The collective bargaining agreements in effect for the IBEW Local 1245; ESC Local 20; and SEIU, United Service Workers West will expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits. The IBEW, ESC, and SEIU represent approximately 62% of the Utility’s employee workforce and support several areas of the Utility’s business, including gas and electric operations. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2022.

PG&E Corporation’s employees are primarily at the executive management level, which experienced significant employee turnover throughout the course of its Chapter 11 Cases in 2019 and 2020. The Utility generally has a stable workforce, which translated into low voluntary turnover during that period. The Utility’s turnover rates for 2022 and 2021 were 7.1% and 5.8%, respectively. Approximately 42% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 19% of PG&E Corporation’s and the Utility’s employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

The Utility’s contractors and subcontractors include approximately 42,000 individuals from approximately 1,200 contractor companies.

Human Capital Management

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce. PG&E Corporation’s and the Utility’s Boards of Directors are responsible for overseeing management’s development and execution of PG&E Corporation’s and the Utility’s human capital strategy.

To build employee engagement, the Utility has a variety of both executive-level and employee-led initiatives and programs. PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and values that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, and community service. The Utility conducts an annual employee engagement survey to measure and improve employee engagement progress.

Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures. In addition, employees are required to complete an annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities.

Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations. PowerPathway helps people throughout the Utility’s service area, including women and military veterans, prepare and compete for high demand jobs in the utility and energy industry. Students receive approximately eight weeks of industry-informed curriculum to ensure the academic, job specific, employability skills and physical training necessary to effectively compete for entry-level employment. Programs may also include hands-on training and on-the-job training.

PG&E Corporation and the Utility also provide integrated solutions and programs that cover employee health and wellness and that encompass physical, emotional, and financial health, including an on-site health clinic, an annual health screening, and health management tools and resources, in addition to more traditional programs.

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PG&E Corporation’s and the Utility’s financial incentives offered to employees include a Short-Term Incentive Plan (“STIP”), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2022 STIP was focused on company objectives of safety, customer impact, and financial health.

All PG&E Corporation and Utility officer compensation currently is funded by shareholders.

Safety

The Utility’s strategy to deliver on safety outcomes focuses on workforce, and public safety. In 2023, in addition to deploying the safety management system, the Utility targets mitigations to the highest risk work. The Utility’s safety metrics include the number of SIF-A incidents and the SIF-P rate, which measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2022, the Utility had seven SIF-A incidents, which resulted in three fatalities and four serious injuries, and a SIF-P rate of 0.11. Additionally, the Utility measures DART. In 2022, the Utility’s DART was 0.67, which was 34% lower than in 2021 and its lowest rate in the past five years.

Throughout the COVID-19 pandemic, PG&E Corporation and the Utility have continued to monitor activities at the Centers for Disease Control and Prevention and the World Health Organization. PG&E Corporation and the Utility have updated their protocols and actions in accordance with guidance from these organizations, following state and local health and safety regulations, and in consultation with the Utility’s medical director. PG&E Corporation and the Utility have also remained focused on protecting the health and safety of their employees, contractors and the Utility’s customers, while continuing to perform critical utility work, and have continued to monitor and track the impact of the pandemic, modifying or adopting new policies in support of their employees’ health and safety as pandemic conditions and governmental response have changed.

Diversity, Equity, Inclusion, and Belonging

PG&E Corporation’s and the Utility’s goal is to foster a diverse, equitable, and inclusive environment that enables all of their coworkers to bring their best selves to work so that they can provide exceptional customer service. These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, People, Shared Services and Supply Chain, with support from the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ diversity, equity, inclusion, and belonging practices and performance.

Key elements of PG&E Corporation’s and the Utility’s approach include active programming to heighten cultural competency, encourage understanding and appreciation of diversity, and integrate thoughtful content into training and performance support materials.

Additionally, the Utility’s 11 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide available programming, certain coworkers lead efforts within their departments, and other specialized teams facilitate dialogue across the companies. These efforts foster employee belonging and support an environment of inclusion that values and respects diversity in the workforce.

In 2022, women, minorities, and military veterans accounted for approximately 26%, 49% and 7%, respectively, of total PG&E Corporation and Utility employees. Approximately 8% of the Utility’s employees are younger than 30, 62% are between the ages of 30 and 49, and 30% are 50 or older.

Electric Utility Operations

The Utility generates electricity and provides electric transmission and distribution services throughout its service area in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides electricity, transmission and distribution services in its service area. 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. For more information, see “Regulatory Matters” in Item 7. MD&A.

Electricity Resources

The Utility is required to maintain adequate capacity 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 responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand.

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The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2022 represented by each major electric resource, and further discussed below. The Utility’s deliveries were primarily from renewable energy resources that qualify under California’s RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California’s RPS requirements and SB 100 goal to serve 100% of retail electricity sales with GHG-free resources by 2045 are discussed further below and in the Environmental Regulation section above.

The total estimated electricity generated, procured, and sold (net), as of December 31, 2022 was 30,307 GWh (1) and comprised of the following:

	Percent of customer retail sales (estimated procurement)		CEC reporting methodology adjustment(2)		Percent of customer retail sales (estimated Power Content Label) (2)
Owned generation facilities
Renewable (3)	2	%	—	%	2	%
Nuclear	49	%	—	%	49	%
Large hydroelectric	7	%	—	%	7	%
Fossil fuel-fired (4)	18	%	(16)	%	2	%
Total	76	%	(16)	%	60	%
Third-party purchase agreements
Renewable (3)	38	%	—	%	38	%
Large hydroelectric	—	%	—	%	—	%
Fossil fuel-fired (4)	16	%	(14)	%	2	%
Total	54	%	(14)	%	40	%
Others, net (2)(5)	(30)	%	30	%	—	%
TOTAL	100	%	—	%	100	%
Total renewable energy resources (3)	40	%	—	%	40	%
GHG-free resources (6)	96	%	—	%	96	%

(1) This amount excludes electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

(2) The allocation of “Others, net” in the “CEC Reporting Methodology Reduction” and “Power Content Label” columns is consistent with CEC guidelines, applied to specified electric generation and procurement volumes (i.e., fossil fuel-fired, nuclear, large hydroelectric, and renewable). Total reported generation and procurement volumes equate to actual electric retail sales.

(3) Amounts include biopower (e.g., biogas, biomass), solar, wind, certain hydroelectric (i.e., 30MW or less), and geothermal facilities. The eligible renewable percentages above do not reflect RPS compliance, which is determined using a different methodology.

(4) Amounts consist primarily of natural gas facilities.

(5) Amount is mainly comprised of net CAISO open market (sales)/purchases.

(6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold.

Renewable Energy Resources

California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. SB 350 increased the amount of renewable energy that must be delivered by most LSEs, 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. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.

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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. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated to comprise 40% of total annual retail sales in 2022.

The estimated total renewable deliveries as of December 31, 2022, shown above was 12,163 GWh and comprised of the following:

Type	Percent of Customer Retail Sales (estimated procurement)(1) (2)
Biopower	5	%
Geothermal	—	%
RPS-Eligible Small Hydroelectric	2	%
Solar	24	%
Wind	9	%
Total	40	%

(1) Estimated renewable procurement amounts are expected to be consistent with Power Content Label reporting and adjustments, based on current CEC guidelines.

(2) Estimated renewable procurement percentages above and renewable compliance percentages are expected to be consistent; however, final RPS compliance reporting is subject to a different methodology and may result in some differences between the two percentages.

Energy Storage

Energy storage improves system reliability and supports California’s decarbonization goals by integrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, under which the Utility was required to procure 580 MW of qualifying storage capacity by the end of 2020, with all energy storage projects required to be operational by the end of 2024. As of December 31, 2022, the Utility was on track to meet its storage goals by the end of 2024.

Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023. In January 2022, the Utility also requested CPUC approval for another 1,600 MW of storage to be completed by the summer of 2024, which would bring the Utility’s total energy storage system capacity to more than 3,330 MW. Finally, the Utility is soliciting 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2026 and 2028.

Owned Generation Facilities

At December 31, 2022, 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	99	2,645
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
Elkhorn Battery Energy Storage System	Monterey County	1	183
Photovoltaic (3):	Various	13	152
Total		130	7,832

(1) The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. The NRC operating licenses currently expire in 2024 and 2025, respectively. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below.

(2) The Utility’s hydroelectric system consists of 102 generating units at 63 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.

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(3) The Utility’s large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW). All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County.

The Utility has applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. (For more information, see “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets” in Item 7. MD&A below.)

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 16 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission

As of December 31, 2022, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 33 electric transmission substations with a capacity of approximately 65,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO.

Electricity Distribution

The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2022, approximately 25% are underground and approximately 75% are overhead), 67 transmission switching substations, and 752 distribution substations with a capacity of approximately 36,000 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. The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

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Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2020 to 2022 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 2022, 2021 or 2020.

	2022		2021		2020
Customers (average for the year)	5,562,223		5,539,969		5,498,044
Deliveries (in GWh) (1)	77,769		78,588		78,497
Revenues (in millions):
Residential	$	6,130	$	6,089	$	5,523
Commercial	5,416		5,042		4,722
Industrial	1,626		1,493		1,530
Agricultural	1,830		1,565		1,471
Public street and highway lighting	77		73		69
Other, net (2)	(247)		(84)		(130)
Subtotal	14,832		14,178		13,185
Regulatory balancing accounts (3)	228		953		673
Total operating revenues	$	15,060	$	15,131	$	13,858
Selected Statistics:
Average annual residential usage (kWh)	5,564		5,889		6,179
Average billed revenues per kWh:
Residential	$	0.2253	$	0.2125	$	0.1852
Commercial	0.1896		0.1802		0.1730
Industrial	0.1177		0.1075		0.1085
Agricultural	0.2435		0.2104		0.2210
Net plant investment per customer	$	9,967	$	9,199	$	8,889

(1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

(2) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, 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 area.  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.  More than 96% of core customers, representing approximately 85% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility generally does not provide procurement service to non-core customers, which must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility with which the Utility has a power purchase agreement that includes its generation fuel expense. 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 area) 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 varied generally based on market conditions. During 2022, the Utility purchased approximately 296,000 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 47% of the total natural gas volume the Utility purchased during 2022.

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, 2022, the Utility’s natural gas system consisted of approximately 44,000 miles of distribution pipelines, over 6,300 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 compressor station on its local transmission system that are used to move gas through the Utility’s pipelines. The Utility’s backbone transmission system 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 the transportation of natural gas from various natural gas supply points and interconnection points to the Utility’s natural gas transportation system. These agreements provide transportation service from western Canada to the United States-Canada border, from the United States-Canada border to an interconnection point with the Utility’s natural gas transportation system at the Oregon-California border, from the U.S. Rocky Mountains to an interconnection point with the Utility’s natural gas transportation system at the Oregon-California border, and 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. (For more information regarding the Utility’s natural gas transportation agreements, see Note 16 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 gas transmission system.  In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility’s owned and operated gas storage fields, Pleasant Creek and Los Medanos. The Utility expects to sell Pleasant Creek in 2023 in accordance with the CPUC’s final decision in the 2019 GT&S rate case. The Utility intends to retain the Los Medanos field to further support system supply reliability as proposed in the 2023 GRC. 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 for withdrawal.  In addition, four independent storage operators are interconnected to the Utility’s Northern California gas transmission system.

In 2022, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and substantially completed its work on the final recommendation from the NTSB’s 2010-11 San Bruno investigation to confirm testing or perform a hydrostatic test for all Class 3 and Class 4 pipelines and all high consequence pipeline mileage.

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Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2020 through 2022 (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 2022, 2021 or 2020.

	2022		2021		2020
Customers (average for the year) (1)	4,585,126		4,563,747		4,545,700
Gas purchased (MMcf)	227,128		226,037		226,746
Average price of natural gas purchased (price per Mcf)	$	7.42	$	3.19	$	2.02
Bundled gas sales (MMcf):
Residential	160,449		162,205		162,682
Commercial	57,066		54,262		49,834
Total Bundled Gas Sales	217,515		216,467		212,516
Revenues (in millions):
Bundled gas sales:
Residential	$	3,353	$	2,759	$	2,517
Commercial	1,005		713		597
Other	163		140		61
Bundled gas revenues	4,521		3,612		3,175
Transportation service only revenue	1,534		1,346		1,211
Subtotal	6,055		4,958		4,386
Regulatory balancing accounts (2)	565		553		225
Total operating revenues	$	6,620	$	5,511	$	4,611
Selected Statistics:
Average annual residential usage (Mcf)	37		37		37
Average billed bundled gas sales revenues per Mcf:
Residential	$	20.22	$	16.54	$	15.09
Commercial	15.19		11.63		10.61
Net plant investment per customer	$	4,522	$	4,130	$	3,794

(1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.

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

Competition

Trends in Market Demand and Competitive Conditions in the Electricity Industry

The Utility expects customer electric load to increase in coming years primarily as a result of electrification of buildings and transportation. The Utility is not able to predict how quickly this electrification will occur. The Utility expects customer demand for gas to decrease in the coming years, primarily in response to policies supporting California’s climate goals.

California law allows qualifying non-residential electric customers of IOUs to purchase electricity from energy service providers rather than from the utilities up to certain annual limits specified for each utility. This arrangement is known as DA. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility.

The Utility continues to provide transmission, distribution, metering, and billing services to DA customers at the election of 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 DA and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers. Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities.

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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 customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, are increasing, putting upward rate pressure on remaining customers. New NEM customers, as well as customers interconnecting on the successor to the NEM tariffs, are required to pay an interconnection fee, utilize time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. See “Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE” in Item 1A. Risk Factors and “Regulatory Matters - OIR to Revisit Net Energy Metering Tariffs” in Item 7. MD&A.

Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers. Those entities may rely upon FERC open access tariffs and Utility infrastructure to deliver energy to them at wholesale rates for resale at retail to existing or potential new Utility customers. These entities may also seek to acquire the Utility’s transmission or distribution facilities through eminent domain for use in serving electricity at retail to existing or potential new Utility customers. As a result, the Utility could lose customers (residential, commercial, and industrial) in the municipality. See “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain” in Item 1A. Risk Factors. It is also expected that some publicly-owned utilities will build new or duplicate transmission or distribution facilities to serve existing or potential new Utility customers. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities.

The effect of such types of retail competition generally is to reduce the number of utility customers, leading to a reduction in the Utility’s rate base.

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

For risks in connection with increasing competition, see Item 1A. Risk Factors.

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.

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 estimates described in Item 7. 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 Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2022 Form 10-K.  Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below.

Risks related to wildfires, including risks related to:

•The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires;

•The 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires;

•Recovery of excess costs in connection with wildfires; and

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•Implementation of wildfire mitigation initiatives.

Risks related to operations and information technology, including risks related to:

•The hazardous nature of the Utility’s electricity and natural gas operations;

•Changes in the electric power and gas industries;

•A cyber incident, cyber security breach, severe natural event or physical attack;

•The operation and decommissioning of the Utility’s nuclear generation facilities; and

•Attracting and retaining specialty personnel.

Risks related to environmental factors, including risks related to:

•Severe weather conditions, extended drought and climate change and events resulting from these conditions (including wildfires); and

•Extensive environmental laws.

Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to:

•The Enhanced Oversight and Enforcement Process;

•Legislative and regulatory developments;

•Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; and

•Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its costs.

Risks related to financial conditions, including risks related to:

•PG&E Corporation’s and the Utility’s substantial indebtedness;

•Restrictions in indebtedness documents;

•Appeals of the Confirmation Order;

•Potential additional dilution to holders of PG&E Corporation common stock;

•Any substantial sale of stock by existing stockholders;

•Ownership and transfer restrictions associated with PG&E Corporation common stock;

•Tax-related risks and uncertainties, including the grantor trust election for the Fire Victim Trust;

•The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income;

•Restrictions on PG&E Corporation’s and the Utility’s ability to issue dividends;

•PG&E Corporation’s reliance on dividends, distributions and other payments from the Utility;

•Restrictions on shareholders’ ability to change the direction or management of PG&E Corporation;

•The COVID-19 pandemic;

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•Increased customer rates; and

•Inflation.

Risks Related to Wildfires

The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.

If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the AB 1054 disallowance cap. Under AB 1054, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Wildfire Fund reimbursement and a reformed prudent manager standard. The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited. In addition, if the Utility fails to maintain a valid safety certification at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility. The Utility will be required to reimburse amounts that are determined by the CPUC not to be just and reasonable. For more information on the disallowance cap, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. If the Utility is unable to maintain an AB 1054 safety certification or if the Wildfire Fund is exhausted, the inability to access the Wildfire Fund could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054.

The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the anticipated ten-year contribution period for the fund. The timing and amount of any potential charges associated with the Utility’s contributions would also depend on various factors. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.

PG&E Corporation and the Utility could be liable as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires.

Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire. Although PG&E Corporation and the Utility have recorded liabilities for probable losses in connection with these fires, these liability estimates correspond to the lower end of the range of reasonably estimable losses, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.

Although there are a number of unknown facts surrounding Cal Fire’s causation determinations of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, the Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have also received and have responded or are responding to document, data, and other information requests from the CPUC’s SED, the DOJ, and law enforcement agencies that are investigating these wildfires. PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Criminal charges have been filed against the Utility in connection with the 2020 Zogg fire. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility currently believes that its total losses associated with the 2020 Zogg fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

There have been numerous other wildfires in the Utility’s service area, of which the Utility has not been alleged or determined to be a cause. The Utility could be alleged or determined to be a cause of one or more of these wildfires.

Additionally, under the doctrine of inverse condemnation, courts have imposed liability against utilities on the grounds that losses borne by the person whose property was damaged through a public-use undertaking should be spread across the community that benefited from such undertaking, even if the utility is unable to recover these costs through rates. In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility’s service area. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines. While the Utility continues to dispute the applicability of inverse condemnation to the Utility, there can be no assurance that the Utility will be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other litigation against PG&E Corporation or the Utility.

Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Despite significant investment in mitigation measures to improve infrastructure and manage vegetation, as well as implementation of de-energization strategies, the Utility may not be successful in mitigating the risk of future wildfires. Once an ignition has occurred, the Utility is unable to control the extent of damages. The extent of damages for a wildfire is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC (including the Safety Culture OII) and the FERC, and future regulatory proceedings, including future applications with the OEIS for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires. For more information about the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility may be unable to recover all or a significant portion of its costs in excess of insurance coverage in connection with wildfires, through rates, or from the Wildfire Fund in a timely manner.

The Utility could incur substantial costs in excess of insurance coverage or amounts potentially available under the Wildfire Fund under AB 1054 in the future in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire. There can be no assurance that the Utility will be allowed to recover costs in excess of insurance or amounts potentially available under the Wildfire Fund under AB 1054 in the future either through FERC TO rates or as costs recorded to the WEMA, even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. The inability to recover all or a significant portion of costs in excess of insurance through rates or by collecting such rates in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. For more information on wildfire recovery risk, see “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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The Utility may not effectively implement its wildfire mitigation initiatives.

The Utility’s infrastructure is aging and poses risks to safety and system reliability. Although the Utility spends significant resources on initiatives designed to mitigate wildfire risks, there is no assurance that these initiatives will be successful or effective in reducing wildfire-related losses. The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, and retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. The CPUC will assess penalties on the Utility if there is a finding that the Utility has failed to substantially comply with its WMPs.

There can be no assurance that the Utility’s wildfire mitigation initiatives will be effective. For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event or where EPSS has been implemented on Utility equipment. The Utility’s inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If the Utility’s wildfire mitigation initiatives are not effective, a wildfire could be ignited and spread.

The PSPS program has been subject to significant scrutiny and criticism by various stakeholders, including customers, regulators, and lawmakers. The Utility also is the subject of a class action litigation in connection with the 2019 PSPS events.

In addition, on a risk-informed basis, the Utility is making efforts to reduce the frequency and impacts of PSPS. The Utility may be subject to mandated changes to, or restrictions on, its operational practices, regulatory fines and penalties, claims for damages, and reputational harm if the Utility does not execute PSPS in compliance with applicable rules and regulations. The Utility establishes the criteria under which it implements PSPS in its territory. To the extent the Utility’s criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions.

PG&E Corporation and the Utility cannot predict the timing and outcome of the various proceedings and litigation in connection with its wildfire mitigation initiatives. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility’s implementation of its wildfire mitigation initiatives, which could result in fines, penalties, customer rebates, other payments, or the Utility’s failure to obtain cost recovery for amounts expended on these initiatives. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other wildfire mitigation initiatives or liability for damages) could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS and EPSS programs have had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events and EPSS outages may increase these negative perceptions. For more information, see “Regulatory Matters” in Item 7. MD&A.

Risks Related to Operations and Information Technology

The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks.

The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. above. 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. For more information, see “The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire” below.

The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably 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 or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption or other catastrophic events;

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

•the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or 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, contractors, 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 wildfire or natural gas explosion);

•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;

•operator or other human error;

•a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences;

•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 damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system;

•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

•attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war. For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event or physical attack” below.

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. Any such incidents also could lead to significant claims against the Utility.

Further, the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, and the Utility may have less control over contractors than its employees. 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 or inactions.

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Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The electric power and gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy.

The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, electric vehicles, energy storage, fuel cells, energy efficiency, and demand response technologies. These developments will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure and state infrastructure modernization (e.g., rail and water projects). The Utility may be unable to effectively adapt to these potential business and regulatory changes, for instance by failing to meet customer demand for new business interconnections in a timely manner. The CPUC is also conducting proceedings to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources and consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. If the Utility is unable to effectively adapt to these potential business and regulatory changes its business model and its ability to execute on its strategy could be materially impacted.

Various jurisdictions within California have enacted prohibitions or restrictions on use and consumption of natural gas, for example in buildings, that will reduce the use of natural gas. Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful,” potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which results in a reduction in associated rate recovery). However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. Inability by the Utility to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

These industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event, or physical attack.

The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks. Private and public entities, such as the North American Electric Reliability Corporation, and the U.S. federal government, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.

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The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. The Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California’s electricity market related to grid modernization and customer choice. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.

The Utility and its third-party vendors have been subject to, and will likely continue to be subject to, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations. None of these breaches or attempts has individually or in the aggregate resulted in a security incident with a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no assurance 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 through rates.

The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease 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 operation of the Diablo Canyon nuclear generation units as well as 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 coverage available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the Utility may be required under federal law to pay up to $275 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States.

The 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 their respective current licenses expire in 2024 and 2025 or prior to the expiration of any renewed license and extended operations period. 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’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

If Diablo Canyon is retired by 2025, 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 Utility. There can be no assurance that the Utility will be successful in retaining highly skilled personnel under its employee programs.

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The Utility is pursuing the extension of operations at Diablo Canyon through no later than 2030. If Diablo Canyon enters extended operations, the Utility will face operational challenges resulting from a shortened planning period. For instance, the Utility may be unable to procure an adequate supply of nuclear fuel. For more information, see “Extension of Diablo Canyon Operations” under “Legislative and Regulatory Initiatives” in Item 7. MD&A.

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 above. If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; 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’s two nuclear generation units before their respective current licenses expire in 2024 and 2025. As of December 31, 2022, the Utility’s unrecovered investment in Diablo Canyon was $840 million.

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 “Asset Retirement Obligations” in Note 3 of the Notes to the Consolidated Financial Statement in Item 8. The Utility’s costs to decommission its nuclear facilities through nuclear decommissioning are subject to reasonableness review by the CPUC. The Utility will be responsible for any costs that the CPUC determines were not reasonably incurred. 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 condition, results of operations, liquidity, and cash flows could be materially affected.

The Utility may be unable to attract and retain specialty personnel.

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 in certain specialty operational positions. Additionally, the Utility could experience labor disruptions from personnel in those positions. If the Utility were to experience such a shortage or disruptions, work stoppages could occur.

Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Risks Related to Environmental Factors

Severe weather conditions, extended drought, and climate change could materially affect PG&E Corporation and the Utility.

Extreme weather, drought and shifting climate patterns have intensified the challenges associated with many of the other risks facing PG&E Corporation and the Utility, particularly wildfire management in California. The Utility’s service area encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as drought conditions and extreme heat followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihood and severity of extraordinary wildfire events. In particular, the risk posed by wildfires, including during the recent wildfire seasons, has increased in the Utility’s service area as a result of an ongoing extended period of drought, bark beetle infestations in the California forest, and wildfire fuel increases due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors. As of December 31, 2022, more than 81% of California is experiencing severe to extreme drought. Moderate or severe drought conditions occur and can persist in virtually all of the Utility’s service area. More than half of the Utility’s service area is in an HFTD. Contributing factors other than environmental can include local land use policies and historical forestry management practices. The combined effects of extreme weather and climate change also impact this risk. In January 2018, the CPUC approved a statewide fire-threat map that shows that approximately half of the Utility’s service area is facing “elevated” or “extreme” fire danger. Approximately 25,000 circuit miles of the Utility’s nearly 80,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs.

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Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility. Any such event could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Any such event also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices or the failure of electric and other equipment of the Utility.

Further, the Utility has been studying the potential effects of climate change (increased severity and frequency of storm events, sea level rise, land subsidence, change in temperature extremes, changes in precipitation patterns and drought, and wildfire) on its assets, operations, and services, and the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant. Consequences of these climate-driven events may vary widely and could include increased stress on the energy supply network due to new patterns of demand, reduced hydroelectric output, physical damage to the Utility’s infrastructure, higher operational costs, and an increase in the number and duration of customer outages and safety consequences for both employees and customers. 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, climate hazards such as heatwaves, windstorms, and flooding caused by rising sea levels and extreme storms could damage the Utility’s facilities, including gas, generation, and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or 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. See “Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE” below.

Events or conditions caused by climate change could have a material impact on the Utility’s operations 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, liquidity, and cash flows could be materially affected.

The Utility’s operations are subject to extensive environmental laws, and such laws could change.

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 16 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, or 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 through 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. and Note 16 of the Notes to the Consolidated Financial Statements in Item 8. The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, changes in estimated costs, and the extent to which actual remediation costs differ from recorded liabilities have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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Risks Related to Other Enforcement Matters, Investigations, and Regulatory Proceedings

PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process.

The EOEP is a six-step process with potentially escalating CPUC oversight and enforcement measures based on specific “triggering events” identified for each of the six steps. If the Utility is placed into the EOEP, it will be subject to additional reporting requirements and additional monitoring and oversight by the CPUC. Higher steps of the process (steps 3 through 6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility’s Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility). The process contains provisions for the Utility to cure and exit the process if it can satisfy specific criteria. The EOEP states that the Utility should presumptively move through the steps of the process sequentially, but the CPUC may place the Utility into the appropriate step of the process upon occurrence of a specified triggering event.

PG&E Corporation and the Utility could be materially affected by legislative and regulatory developments.

The Utility and its operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules. These rules could change, which could change the Utility’s compliance obligations and the costs to comply with these rules. Non-compliance with these rules could result in the imposition of material fines on PG&E Corporation and the Utility, other regulatory exposure, significant litigation, and reputational harm, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Wildfire

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Wildfire Fund does not effectively mitigate the financial risk of liability for damages arising from catastrophic wildfires where the Utility’s facilities are a substantial cause. See “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.” above.

Privacy

In June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The State of California announced enacted regulations in August 2020 and March 2021 which provide guidance on the requirements of the CCPA. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that creates the California Privacy Rights Act (the “CPRA”), which amended and expanded the CCPA. The State of California enacted the CPRA in November 2020, with most provisions operative as of January 1, 2023 and applicable to personal information collected beginning January 1, 2022. Final CPRA regulations are in development. Failure to comply with the CCPA and the CPRA could result in litigation, audits, and the imposition of material fines on PG&E Corporation and the Utility.

Additionally, PG&E Corporation and the Utility collect and retain certain personal information of their customers, shareholders, and employees in connection with their business. Although PG&E Corporation and the Utility invest in risk management and information security measures, the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information. If any of these events were to transpire, it could subject PG&E Corporation and the Utility to financial liability.

PG&E Corporation and the Utility are subject to federal and state privacy laws, which grant consumers rights and protections, including, among other things, the ability to opt out of receiving certain communications and certain data sharing with third parties.

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Environmental

The environmental rules to which the Utility’s operations are subject relate to air quality, water quality and usage, remediation of hazardous substances, and the protection and conservation of natural resources and wildlife.

Also, SB 100 (the 100 Percent Clean Energy Act of 2018) increased the percentage from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from renewable portfolio standard-eligible or carbon-free resources by 2045. Failure to comply with SB 100 could result in fines imposed on PG&E Corporation and the Utility that could be material.

The Utility is subject to extensive regulations and the risk of enforcement proceedings in connection with compliance with such regulations.

The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with the Safety Culture OII (as defined in “Order Instituting an Investigation into PG&E Corporation’s and the Utility’s Safety Culture” under “Regulatory Matters” in Item 7. MD&A) and other matters that the CPUC’s SED may be investigating. The SED could launch investigations at any time on any issue it deems appropriate. In addition, OEIS has authority to approve and oversee compliance with the WMP and may determine that the Utility has failed to substantially comply with its WMP.

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 RA requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC GOs or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance. CPUC staff could also 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 depends on a variety of factors and could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. See “Risks Related to Wildfires” above. The Utility is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.

If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties, the amount of which could be substantial, and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; 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’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively.

The Utility’s financial results depend on its ability to earn a reasonable return on capital, including long-term debt and equity, and to recover costs from its customers, through the rates it charges its customers as approved by the CPUC and the FERC. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility or if the amount of actual costs incurred differs from the forecast or authorized costs embedded in rates. The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including 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. If the CPUC does not authorize sufficient funding for investments in the Utility’s infrastructure, it may negatively impact the Utility's ability to modernize the grid and make it resilient to risks related to climate change, including wildfires.

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In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility’s actual costs differ from authorized or forecast costs. The Utility’s ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time delay between when costs are incurred and when those costs are recovered through rates. The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, the Utility has incurred, and continues to incur, costs to strengthen its wildfire mitigation and prevention efforts before it is clear whether such costs will be recoverable through rates. Also, the CPUC may deny recovery of uninsured wildfire-related costs incurred by the Utility if the CPUC determines that the Utility was not prudent.

The Utility may incur additional costs or receive reduced revenue for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), increased self-generation by customers, an increase in distributed generation, lower customer demand due to adverse economic conditions, the loss of the Utility’s customers to other retail providers like CCAs or DA providers, whether the CAISO wholesale electricity market continues to function effectively, returning customers, or compliance with new state laws or policies. See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1.

Jurisdictions may attempt to acquire the Utility’s assets through eminent domain.

Jurisdictions may attempt to acquire the Utility’s assets through eminent domain (“municipalization”). In particular, the City and County of San Francisco (“San Francisco”) has submitted a petition with the CPUC seeking a valuation of the Utility’s electric assets in San Francisco and has expressed intent to acquire such assets. While San Francisco would still need to, among other things, initiate and prevail in an eminent domain action in state court to acquire the Utility’s assets, there is no guarantee that the Utility would be successful in defending against such an action or related regulatory proceeding. If municipalization proceedings are permitted to move forward and are successful, the Utility would be entitled to receive the fair market value of the assets that are subject to the takeover effort, but the valuation issues in any municipalization proceeding would be highly contentious and could result in the Utility receiving less than what it believes is just compensation for the applicable assets. Any assets acquired by a third party through eminent domain would be excluded from the Utility’s rate base, reducing the Utility’s revenues and opportunity to earn a return on such assets. Assets that are targeted for municipalization generally are located in geographic areas that have a lower cost of service relative to billed revenues, so municipalization could negatively impact the affordability of the Utility’s service for remaining Utility customers served outside of those geographic areas. A successful municipalization attempt could also encourage similar attempts by other municipalities which, if successful, would further divide the Utility’s assets and reduce the Utility’s rate base, profitability, and affordability for remaining Utility customers. It is also unclear how the CPUC would allocate the compensation received by the Utility for its assets between shareholders and customers. As a result of these factors, municipalization could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flow.

Risks Related to PG&E Corporation’s and the Utility’s Environment and Financial Condition

PG&E Corporation’s and the Utility’s substantial indebtedness may adversely affect their financial health and operating flexibility.

PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility. As of December 31, 2022, PG&E Corporation had approximately $4.68 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and borrowings under the $2.75 billion secured term loan agreement entered into in June 2020), and the Utility had approximately $45.6 billion of outstanding indebtedness. In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $1.5 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.

Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility’s assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets. This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including:

•limiting their ability or increasing the costs to refinance their indebtedness;

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•limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes;

•limiting their ability to use operating cash flow in other areas of their business;

•increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and

•limiting their ability to capitalize on business opportunities.

Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks. As a result of the high level of indebtedness, PG&E Corporation and the Utility may be unable to generate sufficient cash through operations to service such debt, and may need to refinance such indebtedness at or prior to maturity and be unable to obtain financing on suitable terms or at all. As a capital-intensive company, the Utility relies on access to the capital markets. If the Utility were unable to access the capital markets or the cost of financing were to substantially increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility’s ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including the Utility’s levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. The Utility’s inability to service its substantial debt or access the financial markets on reasonable terms could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The documents that govern PG&E Corporation’s and the Utility’s indebtedness limit their flexibility in operating their business.

PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to:

•incur or assume indebtedness or guarantees of indebtedness;

•incur or assume liens;

•sell or dispose of all or substantially all of its property or business;

•merge or consolidate with other companies;

•enter into any sale leaseback transactions; and

•enter into swap agreements.

The restrictions contained in these material financing agreements could affect PG&E Corporation’s and the Utility’s ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation’s and the Utility’s ability to finance their operations and expenditures, make strategic acquisitions, investments, or alliances, sell assets, restructure their organization, or finance their capital needs. Additionally, PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions.

Parties have appealed the Confirmation Order.

Following entry of the Confirmation Order confirming the Plan, certain parties filed notices of appeal with respect to the Confirmation Order. While a number of such appeals have been dismissed, there can be no assurance that any of the remaining appeals will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility. See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

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PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.

On the Emergence Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline.

Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8). Such payment may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Any substantial sale of stock by existing stockholders could depress the market value of PG&E Corporation’s common stock, thereby devaluing the market price.

Certain stockholders, including the Fire Victim Trust, received a large number of shares in the Chapter 11 Cases and may continue to hold shares of PG&E Corporation. PG&E Corporation can make no prediction as to the effect, if any, that sales of shares, or the availability of shares for future sale, will have on the prevailing market price of shares of PG&E Corporation common stock. Sales of substantial amounts of shares of common stock in the public market, or the perception that such sales could occur, could depress prevailing market prices for such shares. Such sales may also make it more difficult for PG&E Corporation to sell equity securities or equity-linked securities in the future at a time and price which it deems appropriate.

PG&E Corporation may also sell additional shares of common stock in subsequent offerings or issue additional shares of common stock or securities convertible into shares of PG&E Corporation common stock. The issuance of any shares of PG&E Corporation common stock in future financings, acquisitions upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of PG&E Corporation’s outstanding common stock. If PG&E Corporation issues any such additional shares, the issuance will cause a reduction in the proportionate ownership and voting power of all current shareholders. PG&E Corporation cannot predict the size of future issuances of shares of PG&E Corporation common stock or securities convertible into shares of PG&E Corporation common stock or, for any issuance, the effect, if any, that such future issuances will have on the market price of PG&E Corporation’s common stock.

PG&E Corporation common stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation’s ability to use its net operating loss carryforwards and other tax attributes.

PG&E Corporation has incurred and may also continue to incur, in connection with the Plan, significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid.

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Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities. For more information, see “Because PG&E Corporation and the Utility have elected to treat the Fire Victim Trust as a grantor trust, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act” below. Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.

The Ownership Restrictions remain in effect until the earliest of (i) the repeal, amendment, or modification of Section 382 (and any comparable successor provision) of the IRC, in a manner that renders the restrictions imposed by Section 382 of the IRC no longer applicable to PG&E Corporation, (ii) the beginning of a taxable year in which the Board of Directors of PG&E Corporation determines that no tax benefits attributable to net operating losses or other tax attributes are available, (iii) the date selected by the Board of Directors if it determines that the limitation amount imposed by Section 382 of the IRC as of such date in the event of an “ownership change” of PG&E Corporation (as defined in Section 382 of the IRC and Treasury Regulation Sections 1.1502-91 et seq.) would not be materially less than the net operating loss carryforwards or “net unrealized built-in loss” (within the meaning of Section 382 of the IRC and Treasury Regulation Sections 1.1502-91 et seq.) of PG&E Corporation, and (iv) the date selected by the Board of Directors if it determines that it is in the best interests of PG&E Corporation’s shareholders for the Ownership Restrictions to be removed or released. The Ownership Restrictions may also be waived by the Board of Directors on a case by case basis.

Because PG&E Corporation and the Utility have elected to treat the Fire Victim Trust as a grantor trust, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act.

The Plan contemplated that the Fire Victim Trust would be treated as a “qualified settlement fund” for U.S. federal and state income tax purposes, subject to PG&E Corporation’s ability to elect to treat the Fire Victim Trust as a grantor trust for U.S. federal and state income tax purposes instead. On July 8, 2021, PG&E Corporation, the Utility, ShareCo, and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a grantor trust election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust.

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the Ownership Restrictions. See “Tax Matters” in Item 7. MD&A for an example of these calculations. PG&E Corporation does not control the number of shares held by the Fire Victim Trust and is not able to determine in advance the number of shares the Fire Victim Trust will hold. PG&E Corporation intends to periodically make available to investors information about the number of shares of common stock held by the Fire Victim Trust, the Utility, and ShareCo as of a specified date for purposes of the Ownership Restrictions, including in its Quarterly Reports and Annual Reports filed with the SEC.

PG&E Corporation intends to enforce the Ownership Restrictions as described in the foregoing paragraph (calculated as excluding any shares owned by the Fire Victim Trust, the Utility, and ShareCo from the number of outstanding equity securities). All current and prospective shareholders are advised to consider the foregoing in determining their ownership and acquisition of PG&E Corporation common stock.

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PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to

offset future income.

As of December 31, 2022, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $26.6 billion and $25.2 billion, respectively, and PG&E Corporation incurred and may also continue to incur, in connection with the Plan, significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the IRC (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years).

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC. However, whether PG&E Corporation underwent or will undergo an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects. Accordingly, there can be no assurance that the Internal Revenue Service would not successfully assert that PG&E Corporation has undergone or will undergo an ownership change pursuant to the Plan. In addition, even if these transactions did not cause an ownership change, they may increase the likelihood that PG&E Corporation may undergo an ownership change in the future. If the Internal Revenue Service successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. In addition, PG&E Corporation’s ability to utilize its net operating loss carryforwards to fund a customer credit trust is critical to whether the impact of the fixed recovery charges paid by customers pursuant to the SB 901 securitization transactions will be neutral, on average, to such customers. Further, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock.

PG&E Corporation’s ability to pay dividends on shares of its common stock is subject to restrictions.

Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s Board of Directors and will depend on, among other things, PG&E Corporation’s results of operations, financial condition, cash requirements, contractual restrictions, and other factors that the Board of Directors may deem relevant.

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PG&E Corporation is a holding company and relies on dividends, distributions and other payments, advances, and transfers of funds from the Utility to meet its obligations.

PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility. Accordingly, PG&E Corporation’s cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility. The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in the agreements of those subsidiaries. Additionally, 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 to meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the 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. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to meet its obligations.

California law and certain provisions in the Amended Articles and the amended and restated bylaws of PG&E Corporation (the “Amended Bylaws”) may prevent efforts by shareholders to change the direction or management of PG&E Corporation.

The Amended Articles and the Amended Bylaws contain provisions that may make the acquisition of PG&E Corporation more difficult without the approval of the Board of Directors, including the following:

•until 2024, the Board of Directors will be divided into two equal classes, with members of each class elected in different years for different terms;

•only holders of shares who are entitled to cast ten percent or more of the votes can request a special meeting of the shareholders, and any such request must satisfy the requirements specified in the Amended Bylaws; action by shareholders may otherwise only be taken at an annual or special meeting duly called by or at the direction of a majority of the Board of Directors, or action by written consent signed by shareholders owning at least the number of votes necessary to authorize the action at a meeting where all shares entitled to vote were present;

•advance notice for all shareholder proposals is required; and

•any person acquiring PG&E Corporation Equity Securities will be restricted from owning 4.75% or more of such Equity Securities (as determined for federal income tax purposes (see “Tax Matters” in Item 7. MD&A)), subject to certain exceptions as may be determined by the Board of Directors of PG&E Corporation.

These and other provisions in the Amended Articles, the Amended Bylaws, and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delaying or impeding merger, tender offer, or proxy contest involving PG&E Corporation. The existence of these provisions could negatively affect the price of PG&E Corporation common stock and limit opportunities for shareholders to realize value in a corporate transaction.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows have been (beginning in March 2020) and could continue to be significantly affected by the outbreak of the COVID-19 pandemic (and its variants), but the extent of such impact is uncertain.

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PG&E Corporation and the Utility continue to evaluate the impact of the current COVID-19 outbreak on their business and financial results. The consequences of a continued and prolonged outbreak and resulting governmental and regulatory orders have had and could continue to have a negative impact on the Utility’s financial condition, results of operations, liquidity, and cash flows.

The outbreak of the COVID-19 pandemic and the resulting economic conditions, and resulting decrease in economic and industrial activity in the Utility’s service area, have and will continue to have a significant adverse impact on the Utility’s customers. These circumstances have impacted and will continue to impact the Utility for a period of time that PG&E Corporation and the Utility are unable to predict. For example, the economic downturn has resulted in a reduction in customer receipts and collection delays throughout the COVID-19 pandemic.

The Utility’s accounts receivable balances over 30 days outstanding as of December 31, 2022 were approximately $1.1 billion, or $890 million higher as compared to the balances as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections for as long as current COVID-19 circumstances persist.

PG&E Corporation and the Utility are unable to quantify the long-term potential impact of the changes in customer collections or changes in energy demand on earnings and cash flows due, in part, to uncertainties regarding the timing, duration and intensity of the COVID-19 outbreak and the resulting economic downturn. Although the CPUC authorized the establishment of memorandum and balancing accounts to track costs associated with customer protection measures, the timing of regulatory relief, if any, and ultimate cost recovery from such accounts or otherwise, are uncertain.

The COVID-19 pandemic and resulting economic downturn have resulted and may continue to result in workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment. Increased governmental regulation of the COVID-19 pandemic protections, including vaccination mandates or testing requirements for workers, could result in employee attrition, workforce disruptions and increased supplier and contractor costs.

Although the Utility continues to prioritize customer and community safety, these disruptions necessitate changes to the Utility’s operating and capital expenditure plans, which could lead to project delays or service disruptions in certain programs. Delays in production and shipping of materials used in the Utility’s operations may also impact operations.

The Utility has experienced shortages in certain materials, longer lead times and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of the COVID-19 pandemic. Potential longer-term impacts of the COVID-19 pandemic on PG&E Corporation or the Utility include the potential for higher credit spreads, borrowing costs and incremental financing needs. PG&E Corporation’s and the Utility’s analysis of the potential impact of the COVID-19 pandemic is ongoing and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 pandemic situation and any resurgence of the COVID-19 pandemic and any variant strains of the COVID-19 virus, the effectiveness and intensity of measures to contain the COVID-19 pandemic (including availability and effectiveness of vaccines), and the effects of the COVID-19 situation on the business, financial condition and results of operations of PG&E Corporation and the Utility and on the business and general economic conditions in the State of California and the United States of America.

Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE.

The rates paid by the Utility’s customers are impacted by the Utility’s costs, commodity prices, and broader energy trends. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. In particular, the Utility will need to make substantial, sustained investments to its infrastructure to adapt to climate change. For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively” above. If customer rates increase, the CPUC may face greater pressure to approve lesser amounts in the Utility’s ratemaking or cost recovery proceedings.

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The Utility generally recovers its electricity and natural gas procurement costs through rates as “pass-through” costs. Increases in the Utility’s commodity costs directly impact customer bills.

Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers to receive bill credits for power exported to the grid at the full retail rate, shifts costs to other customers. Under this structure, NEM customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, including costs associated with funding social equity programs, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. These unpaid costs are subsidized by customers not participating in NEM. Accordingly, as more electric customers switch to NEM and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM customers.

Other long-term trends could also increase costs for gas customers. Natural gas suppliers are subject to compliance with CARB’s cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). CARB may also require aggressive energy efficiency programs to reduce natural gas end use. Increased renewable portfolio standards in the electric sector could reduce electric generation gas load. Additionally, customers replacing natural gas appliances with electric appliances will lead to further reduced gas demand. The combination of reduced load and increased costs to maintain the gas system could result in higher natural gas customer bills. In addition, some local city governments have passed ordinances restricting use of natural gas in new construction and, if other jurisdictions follow suit, this could affect future demand for the provision of natural gas. If fewer customers receive gas from the Utility, the Utility’s gas system maintenance costs, many of which cannot be reduced in the short term even if gas quantities decrease, would be borne by fewer customers. Finally, a mandate to purchase renewable natural gas for core customers could lead to increased costs for core customers if utilities are competing with the transportation sector for supplies of renewable natural gas.

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 reduce energy demand. 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 increase the energy rates for other customers.

If rates were to rise too rapidly, customer usage could decline. This decline would decrease the volume of sales, among which the Utility’s costs are allocated, and increase rates.

To relieve some of this upward rate pressure, the CPUC may authorize lower revenues than the Utility requested or increase the period over which the Utility is allowed to recover amounts, which could impact the Utility’s ability to timely recover its operating costs. The Utility’s level of authorized capital investment could decline as well, leading to a slower growth in rate base and earnings. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

Inflation may negatively impact PG&E Corporation’s and the Utility’s financial conditions, results of operations, liquidity, and cash flows.

PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased. Long-term inflationary pressures may result in such prices continuing to increase more quickly than expected. Increases in inflation raises costs for labor, materials and services, and PG&E Corporation and the Utility may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely impact PG&E Corporation’s and the Utility’s financial conditions, results of operations, liquidity, and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

The Utility owns or has obtained the right to occupy or use real property comprising the Utility’s electricity and natural gas distribution facilities, electric generation 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 primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies 9 million square feet of real property, including 7 million square feet owned by the Utility. On September 17, 2021, the sale of the SFGO closed and the Utility entered into a leaseback agreement with the new SFGO owner (the “Leaseback Agreement”) to lease back certain space within the SFGO to allow for additional time to relocate critical facilities to other Utility sites. The Leaseback Agreement commenced on September 17, 2021 and continues through various dates for the various leased spaces, with December 31, 2023 being the latest lease expiration date. On October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters. The term of the lease began on April 8, 2022 and the lease grants the Utility an option to purchase the legal parcel that contains the Lakeside Building. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation also leased approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease expired, and the leased premises were surrendered at the end of February 2022.

The Utility owns approximately 148,000 acres of land, including approximately 121,000 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 40,000 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 LCC transactions by the end of 2023, subject to securing all required regulatory approvals.

ITEM 3. LEGAL 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 “Litigation Matters” in Item 7. MD&A, Item 1A. Risk Factors and Notes 2, 15, and 16 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable. 

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following individuals serve as executive officers of PG&E Corporation, as of February 22, 2023. Except as otherwise noted, all positions have been held at PG&E Corporation.

Name	Age	Positions Held Over Last Five Years	Time in Position
Patricia K. Poppe	54	Chief Executive Officer	January 4, 2021 to present
		President and Chief Executive Officer, CMS Energy Corporation	July 2016 to December 2020
		Vice President, Customer Experience, Rates and Regulations, Consumers Energy Company	January 2011 to July 2016
Christopher A. Foster	44	Executive Vice President and Chief Financial Officer	March 20, 2021 to present
		Vice President and Interim Chief Financial Officer	September 26, 2020 to March 20, 2021
		Vice President, Treasury and Investor Relations	March 9, 2020 to September 25, 2020
		Senior positions within PG&E Corporation’s Investor Relations department, including as its Vice President starting in December 2018	November 2017 to March 8, 2020

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		Senior positions within PG&E Corporation and the Utility, including Director, Integrated Grid Planning and Innovation from June 2016 to October 2017	September 2011 to October 2017
Carla J. Peterman	44	Executive Vice President, Corporate Affairs and Chief Sustainability Officer	October 1, 2021 to present
		Executive Vice President, Corporate Affairs	June 1, 2021 to September 30, 2021
		Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison	September 2019 to May 2021
		Commissioner, California Public Utilities Commission	December 2012 to December 2018
Julius Cox	51	Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to present
		Senior Vice President & Chief Human Resources Officer, American Electric Power	October 2019 to January 2021
		Executive Vice President & Chief Transformation Officer, Dynegy Inc.	September 2017 to April 2018
		Executive Vice President & Chief Administrative Officer, Dynegy Inc.	October 2014 to September 2017
Ajay Waghray	61	Senior Vice President and Chief Information Officer	September 21, 2020 to present
		Founder, Agni Growth Ventures, LLC	January 2019 to September 2021
		Executive Vice President and Chief Technology Officer, Assurant Inc.	May 2016 to December 2018
Sumeet Singh	44	Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to present
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to December 31, 2021
		Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation	January 1, 2021 to January 31, 2021
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	August 2020 to December 31, 2021
		Gas Safety & Integrity Officer, Energy, Picarro, Inc.	February 2020 to August 2020
		Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018	September 2015 to January 2020
John R. Simon	58	Executive Vice President, General Counsel and Chief Ethics & Compliance Officer	August 15, 2020 to present
		Executive Vice President, Law, Strategy, and Policy	June 2019 to August 2020

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		Executive Vice President	May 2019 to June 2019
		Interim Chief Executive Officer	January 2019 to May 2019
		Executive Vice President and General Counsel	March 2017 to January 2019
		Executive Vice President, Corporate Services and Human Resources	August 2015 to February 2017
Adam L. Wright	45	Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company	February 1, 2021 to present
		Chief Executive Officer and President, MidAmerican Energy Company	January 2018 to January 26, 2021
		President of MidAmerican Funding LLC	January 2018 to January 26, 2021
		Vice President, Gas Delivery, MidAmerican Energy Company	May 2015 to January 2018
		Vice President, Wind Generation & Development, MidAmerican Energy Company	January 2012 to May 2015
Marlene M. Santos	62	Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company	March 15, 2021 to present
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
Jason M. Glickman	42	Executive Vice President, Engineering, Planning, and Strategy, Pacific Gas and Electric Company	May 3, 2021 to present
		Global Head of Utilities and Renewables, Bain & Company	March 2020 to April 2021
		Partner, Bain & Company	January 2014 to April 2021
		Consultant, Bain & Company	August 2007 to December 2013

The following individuals serve as executive officers of the Utility as of February 22, 2023. Except as otherwise noted, all positions have been held at the Utility.

Adam L. Wright	45	Executive Vice President, Operations and Chief Operating Officer	February 1, 2021 to present
		Chief Executive Officer and President, MidAmerican Energy Company	January 2018 to January 26, 2021
		President of MidAmerican Funding LLC	January 2018 to January 26, 2021
		Vice President, Gas Delivery, MidAmerican Energy Company	May 2015 to January 2018
		Vice President, Wind Generation & Development, MidAmerican Energy Company	January 2012 to May 2015
Marlene M. Santos	62	Executive Vice President and Chief Customer Officer	March 15, 2021 to present
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
Jason M. Glickman	42	Executive Vice President, Engineering, Planning, and Strategy	May 3, 2021 to present
		Global Head of Utilities and Renewables, Bain & Company	March 2020 to April 2021
		Partner, Bain & Company	January 2014 to April 2021

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		Consultant, Bain & Company	August 2007 to December 2013
Stephanie N. Williams	40	Vice President, Chief Financial Officer and Controller, Pacific Gas and Electric Company	January 10, 2023 to present
		Vice President, Finance and Planning	January 2020 to January 10, 2023
		Senior Director, Business Finance Electric Operations	March 2019 to January 10, 2022
		Director, Business Finance	October 2014 to February 2019
Julius Cox	51	Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to present
		Senior Vice President & Chief Human Resources Officer, American Electric Power	October 2019 to January 2021
		Executive Vice President & Chief Transformation Officer, Dynegy Inc.	September 2017 to April 2018
		Executive Vice President & Chief Administrative Officer, Dynegy Inc.	October 2014 to September 2017
Sumeet Singh	44	Executive Vice President, Chief Risk Officer and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to present
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to December 31, 2021
		Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation	January 1, 2021 to January 31, 2021
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	August 2020 to December 31, 2021
		Gas Safety & Integrity Officer, Energy, Picarro, Inc.	February 2020 to August 2020
		Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018	September 2015 to January 2020

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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 16, 2023, there were 43,782 holders of record of PG&E Corporation common stock. A substantially greater number of holders of PG&E Corporation common stock are “street name” or beneficial holders, whose shares of record are held by banks, brokers, and other financial institutions. PG&E Corporation common stock is listed on the New York Stock Exchange and is traded under the symbol “PCG.” Shares of common stock of the Utility are wholly owned by PG&E Corporation and do not trade in the public market.

For information regarding dividends, see “Liquidity and Financial Resources - Dividends” in Item 7. MD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 8 of the Notes to the Consolidated Financial Statements in Item 8.

Share Exchanges

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. On the dates and in the amounts set forth in the table below, the Fire Victim Trust exchanged a total of 290,000,000 Plan Shares, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares.

Date	Shares Exchanged
January 31, 2022	40,000,000
April 14, 2022	60,000,000
October 4, 2022	35,000,000
October 27, 2022	35,000,000
December 12, 2022	60,000,000
January 9, 2023	60,000,000
Total Shares Exchanged	290,000,000

Each exchange was effected in reliance on the exemption from registration under Section 3(a)(10) of the Securities Act. See “Tax Matters” in Item 7. MD&A below and “Share Exchange and Tax Matters Agreement” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K for a detailed discussion of the exchange and the terms of the Share Exchange and Tax Matters Agreement, respectively.

ITEM 6. [RESERVED]

Not applicable.

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

OVERVIEW

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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Key Factors Affecting Financial Results

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

•The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, the Wildfire Fund, and regulatory recovery.

In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2022 the Utility expanded the EPSS program to all high fire risk areas. The Utility is also focused on undergrounding more lines each year while using economies of scale to make undergrounding more cost efficient. These initiatives significantly reduced the number of CPUC-reportable ignitions and the number of acres burned. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions.

PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it is undertaking a review and has identified instances of noncompliance. The Utility intends to update the CPUC and OEIS as its review progresses. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for the late inspections or other noncompliance related to wildfire mitigation efforts. See “Self-Reports to the CPUC” in “Regulatory Matters” below.

Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Once an ignition has occurred, the Utility is unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of December 31, 2022, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.025 billion, $400 million, $1.175 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses but do not include all categories of potential damages and losses.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 31 counts in connection with the 2020 Zogg fire, of which the court has dismissed 20 counts. If the Utility were to be convicted of any of the remaining charges, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements. Accordingly, depending on which charges the Utility were to be convicted of, its total losses associated with the 2020 Zogg fire could materially exceed the $400 million of aggregate liability that PG&E Corporation and the Utility have recorded.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage through the Wildfire Fund, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. As of December 31, 2022, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $370 million for the 2020 Zogg fire, $530 million for the 2021 Dixie fire, and $45 million for the 2022 Mosquito fire. Additionally, the Utility does not expect that any of its liability insurance would cover restitution payments, if such payments were ordered by the court presiding over the criminal proceeding in connection with the 2020 Zogg fire.

If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of December 31, 2022, the Utility has recorded a Wildfire Fund receivable of $175 million for the 2021 Dixie fire. See “Wildfire Fund under AB 1054” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility will be permitted to recover its wildfire-related claims and legal fees through rates only if the CPUC or the FERC, as applicable, determines that the Utility has met the prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables. As of December 31, 2022, the Utility has recorded receivables for regulatory recovery of $503 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 for more information.

•The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. 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, administrative and general expenses) and capital costs (e.g., depreciation 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” below), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. The Utility has also applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 4 and 16 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below.

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility is subject to enforcement, litigation, and regulatory matters, including those described above, the Safety Culture OII, EOEP proceedings, and actions in connection with the Utility’s WMP, and safety and other self-reports. See Note 16 of the Notes to the Consolidated Financial Statements in Item 8. In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. See “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain” in Item 1A. Risk Factors for more information. These matters could result in penalties, additional regulatory requirements, or changes to the Utility’s operations. PG&E Corporation and the Utility seek to limit these matters by implementing a robust compliance program and by delivering excellent customer experiences.

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•PG&E Corporation’s and the Utility’s Ability to Control Operating Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also reducing non-fuel Operating and maintenance costs by two percent per year. The Utility’s ability to meet this goal depends on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors.  In addition, this annual report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are unable 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.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $26.6 billion and California net operating loss carryforward of approximately $25.2 billion as of December 31, 2022.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. At various dates throughout 2022, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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Update on Ownership Restrictions in PG&E Corporation’s Amended Articles

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility, and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of outstanding shares. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2022 and 2021.  See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

See “Results of Operations” in Item 7 of the 2021 Form 10-K for discussion of results of operations for 2021 compared to 2020.

PG&E Corporation

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

(in millions)	2022		2021
Consolidated Total	$	1,800	$	(102)
PG&E Corporation	(412)		(226)
Utility	2,212		124

PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt. The increase in PG&E Corporation’s net loss for 2022, as compared to 2021, is primarily due to increased interest rates on long-term debt.

Utility

The table below shows certain items from the Utility’s Consolidated Statements of Income for 2022 and 2021.  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.

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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.

	2022						2021
	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
Electric operating revenues	$	10,357	$	4,703	$	15,060	$	9,542	$	5,589	$	15,131
Natural gas operating revenues	3,939		2,681		6,620		3,753		1,758		5,511
Total operating revenues	14,296		7,384		21,680		13,295		7,347		20,642
Cost of electricity	—		2,756		2,756		—		3,232		3,232
Cost of natural gas	—		2,100		2,100		—		1,149		1,149
Operating and maintenance	6,737		2,988		9,725		6,820		3,374		10,194
SB 901 securitization charges, net	608		—		608		—		—		—
Wildfire-related claims, net of insurance recoveries	237		—		237		258		—		258
Wildfire Fund expense	477		—		477		517		—		517
Depreciation, amortization, and decommissioning	3,856		—		3,856		3,403		—		3,403
Total operating expenses	11,915		7,844		19,759		10,998		7,755		18,753
Operating income (loss)	2,381		(460)		1,921		2,297		(408)		1,889
Interest income	162		—		162		22				22
Interest expense	(1,658)		—		(1,658)		(1,373)		—		(1,373)
Other income, net	135		460		595		104		408		512
Reorganization items, net	—		—		—		(12)		—		(12)
Income before income taxes	$	1,020	$	—	$	1,020	$	1,038	$	—	$	1,038
Income tax provision (benefit) (1)					(1,206)						900
Net income					2,226						138
Preferred stock dividend requirement (1)					14						14
Income Attributable to Common Stock					$	2,212					$	124

(1) These items impacted earnings.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2022 and 2021, 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 by $1.0 billion, or 8%, in 2022 compared to 2021, primarily due to the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below), the recognition of approximately $180 million in revenues related to the final decision approving $356.3 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system (see “2015 Gas Transmission and Storage Rate Case” below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate. In addition, the Utility recognized approximately $113 million in nuclear decommissioning revenues in 2022 with no comparable revenues in 2021. This is consistent with the 2018 NDCTP final decision that authorized no decommissioning revenues for 2021 and $113 million in revenues in 2022. These increases were partially offset by a decrease of approximately $180 million of previously deferred revenues recognized in conjunction with interim rate relief collected in 2021 associated with the 2020 WMCE application (see “2020 WMCE Application” below).

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Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings decreased by $83 million, or 1%, in 2022 compared to 2021, as a result of operating cost efficiencies and decreases in the recognition of previously deferred costs including $90 million related to residential uncollectibles and approximately $180 million recognized in conjunction with interim rate relief associated with the 2020 WMCE application (see “2020 WMCE Application” below). In addition, during the year ended December 31, 2021, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2022. These decreases were partially offset by the recognition of approximately $310 million of previously deferred expenses, which were authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below) in the year ended December 31, 2022, compared to the same period in 2021.

SB 901 Securitization Charges, Net

SB 901 securitization charges, net, that impacted earnings increased by $608 million, or 100%, in 2022 compared to 2021. During the year ended December 31, 2022, the Utility recorded $608 million in net SB 901 securitization charges, for inception of the regulatory asset and liability pursuant to the CHT decision, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock, with no comparable charges in 2021. For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 below.

Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires that impacted earnings decreased by $21 million, or 8%, in 2022 compared to 2021. The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in the year ended December 31, 2022. These charges were partially offset by $95 million of probable recoveries through insurance and the WEMA related to the 2022 Mosquito fire and $25 million in probable recoveries through the Wildfire Fund related to the 2021 Dixie fire. The Utility recognized pre-tax charges of $1.15 billion related to the 2021 Dixie fire, $175 million related to the 2019 Kincade fire, and $100 million related to the 2020 Zogg fire in the year ended December 31, 2021, partially offset by $1.06 billion of probable recoveries through insurance, the WEMA, and the Wildfire Fund related to the 2021 Dixie fire and $100 million of probable insurance recoveries related to the 2020 Zogg fire in the year ended December 31, 2021. See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 below.

In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $125 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims.

See Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Wildfire Fund Expense

Wildfire Fund expense that impacted earnings decreased by $40 million, or 8%, in 2022 compared to 2021, primarily due to accelerated amortization of the Wildfire Fund asset recorded in 2021 as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire, with no material amounts recorded in 2022.

See Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Item 8.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased by $453 million, or 13%, in 2022 compared to 2021, primarily due to an increase in net capital additions and an increase in decommissioning expense beginning in January 2022 primarily as a result of the final 2018 NDCTP decision.

Interest Income

The Utility’s interest income that impacted earnings increased by $140 million, or 636%, in 2022 compared to 2021, primarily due to higher interest rates earned on regulatory balancing accounts.

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Interest Expense

Interest expense that impacted earnings increased by $285 million, or 21%, in 2022 compared to 2021, primarily due to the issuance of additional long-term debt and an increase in interest rates on variable-rate debt.

Other Income, Net

Changes to Other income, net that impact earnings are primarily driven by fluctuations in the balance of construction work in progress that impact the equity component of AFUDC, and gains and losses on equity securities held by the customer credit trust.

Income Tax Provision (Benefit)

Income tax benefit increased by $2.1 billion in 2022 compared to 2021, primarily due to a write-off of a DTA associated with the grantor trust election for the Fire Victim Trust in the year ended December 31, 2021 and a benefit recognized related to the sale of shares in the Fire Victim Trust in the year ended December 31, 2022.

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

	2022		2021
Federal statutory income tax rate	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(26.9)	%	24.1	%
Effect of regulatory treatment of fixed asset differences (2)	(49.2)	%	(51.6)	%
Tax credits	(1.3)	%	(1.2)	%
Fire Victim Trust (3)	(64.0)	%	91.9	%
Other, net	2.2	%	2.6	%
Effective tax rate	(118.2)	%	86.8	%

(1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes 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. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act.

(3) Includes the tax benefit of the sale of shares by the Fire Victim Trust in 2022 and the tax effect of the grantor trust election for the Fire Victim Trust in 2021. See “Tax Matters” above and Note 7 of the Notes to the Consolidated Financial Statements in Item 8.

Utility Revenues and Costs that did not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs. See below for more information.

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Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs 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. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), 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. The cost of electricity decreased in 2022 as compared to 2021. This was primarily due to decreased customer demand and higher energy sales to the CAISO, partially offset by higher fuel prices.

(in millions)	2022		2021
Cost of purchased power, net	$	2,283	$	2,883
Fuel used in own generation facilities	473		349
Total cost of electricity	$	2,756	$	3,232

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 11 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas increased in 2022 as compared to 2021 due to increased customer demand and higher market prices. This was driven primarily by below-normal winter temperatures and prolonged drought conditions, resulting in lower California and Pacific Northwest hydro-electric generation output and higher demand from natural-gas fired generation. Lower natural gas storage levels and regional pipeline constraints also contributed to higher natural gas prices.

(in millions)	2022		2021
Cost of natural gas sold	$	1,957	$	1,010
Transportation cost of natural gas sold	143		139
Total cost of natural gas	$	2,100	$	1,149

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.  If the Utility were to spend more than authorized amounts, these expenses could have an impact on earnings.

Other Income, Net

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

Nuclear Operations

Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon’s generation to the California electricity market. Management analyzes capacity factors by comparing Diablo Canyon’s actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms.

Apart from cost-of-service ratemaking and beginning on September 2, 2022, the Utility is entitled to receive a monthly performance-based disbursement. For more information, see “Extension of Diablo Canyon Operations” below.

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The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility’s wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the years ended December 31, 2022 and 2021, Diablo Canyon achieved an average capacity factor of 90% and 84%, respectively. As previously disclosed, Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to excessive vibrations within the main generator.

In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to assure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to have sufficient liquidity to fund their present and future commitments.

The Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, 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 retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets.

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including 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. The collateral posting provisions for some of the Utility’s power and natural gas commodity, and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

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Arrearages Related to the COVID-19 Pandemic

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. In particular, the Utility continues to experience increased arrearages. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, an annual cap set by the CPUC on the number of service disconnections for residential customers, and the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections.” The Utility resumed non-residential and residential service disconnections as of October 13, 2022. The Utility’s accounts receivable balances over 30 days outstanding as of December 31, 2022, were approximately $1.1 billion, or $890 million higher as compared to the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic.

As of December 31, 2022, PG&E Corporation and the Utility had access to approximately $2.9 billion of total liquidity comprised of approximately $609 million of Utility cash, $125 million of PG&E Corporation cash and $2.2 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See “Cost of Capital Proceedings” below for more information.

The Utility established the CPPMA for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of December 31, 2022, the CPPMA totaled $26 million and is reflected in Long-term regulatory assets on the Consolidated Balance Sheets. In addition to the $26 million recorded to the CPPMA, the Utility recorded approximately $126 million of under-collections from residential customers from March 4, 2020 to December 31, 2022 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Consolidated Balance Sheets.

On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs. The Utility received approximately $200 million in November 2022 to reduce the amounts owed by customer accounts in arrears. The amount of funding was determined by the California Department of Community Services and Development, which is the agency responsible for administering the CAPP.

Because electric rates have been set using a sales forecast that has been adjusted for impacts of the COVID-19 pandemic, PG&E Corporation and the Utility do not expect significant variances between the forecast of electric usage and actual electric usage due to COVID-19 in 2023. Consequently, PG&E Corporation and the Utility do not expect the COVID-19 pandemic to result in undercollections.

The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

Cash, Cash Equivalents, and Restricted Cash

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 primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. 

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Financial Resources

Equity Financings

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in “At the Market Equity Distribution Program” in Note 7 of the Notes to the Consolidated Financial Statements in Item 8), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in “At the Market Equity Distribution Program” in Note 7 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date for this program, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement.

PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets” below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

Debt Financings

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of a portion of the loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

SB 901 Securitization

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

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The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement as defined below, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024.

AB 1054 Securitization

On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The net proceeds were used by the Utility to fund fire risk mitigation capital expenditures that were incurred by the Utility from the period beginning October 2021 through October 2022.

For more information, see “AB 1054” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Facilities

As of December 31, 2022, PG&E Corporation and the Utility had $500 million and $1.5 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the amendment. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time.

Utility

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

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On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On July 1, 2020, the Utility entered into the Utility Revolving Credit Agreement, which it subsequently amended. On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into the Corporation Revolving Credit Agreement, which it subsequently amended. On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

For more information, see “Credit Facilities” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the dividends paid in arrears, the Utility paid approximately $11 million of dividends on redeemable preferred stock during the year ended December 31, 2022. On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023.

On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

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Subject to the dividend restrictions described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8, any decision to declare and pay dividends on PG&E Corporation’s common stock in the future will be made at the discretion of the Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions of PG&E Corporation, and other factors that the Board of Directors of PG&E Corporation may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for 2022 and 2021. 

See “Liquidity and Financial Resources” in Item 7 of the 2021 Form 10-K for discussion of the Utility’s cash flows for 2021 compared to 2020.

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2022		2021
Net cash provided by (used in) operating activities	$	3,831	$	2,448
Net cash used in investing activities	(10,069)		(7,050)
Net cash provided by financing activities	6,879		4,379
Net change in cash, cash equivalents, and restricted cash	$	641	$	(223)

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 2022, net cash provided by operating activities increased by $1.4 billion compared to the same period in 2021.  This increase was partially due to an increase in base revenues authorized in the 2020 GRC and additional revenues as authorized through the FERC formula rate and a decrease in operating and maintenance expense as a result of operating cost efficiencies. In addition, during 2022, the Utility made a payment to the Fire Victim Trust of $592 million as compared to a payment of $758 million in the same period in 2021.

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

•the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Wildfire-Related Securities Class Action” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below for more information);

•the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service area, the ability of the Utility to collect on its customer receivables, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing;

•the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires;

•the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

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•the timing and amounts of available funds collected for self-insurance (see “2023 General Rate Case” in the Regulatory Matters section of Item 7. Management’s Discussion and Analysis for more information);

•the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Investing Activities

Net cash used in investing activities increased by $3.0 billion during 2022 as compared to the same period in 2021. This increase was primarily driven by a $1.9 billion increase in capital expenditures, including additional system hardening and emergency response work performed in 2022. Additionally, the Utility purchased $1.0 billion of investments as part of the creation of the customer credit trust, with no similar purchases in 2021.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.9 billion and $11.2 billion in 2023. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building, and the timing and amount of contributions to the customer credit trust, including shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

Financing Activities

Net cash provided by financing activities increased by $2.5 billion during 2022 as compared to the same period in 2021. The increase was primarily due to the issuance of $7.5 billion of SB 901 recovery bonds and a decrease of $850 million in net repayments of short-term debt. These increases were partially offset by a $5.9 billion increase in amounts paid to satisfy long-term debt outstanding in 2022 compared to the same period in 2021.

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 or prepayment date of existing debt instruments.  Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

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 2, Note 15, and 16 of the Notes to the Consolidated Financial Statements in Item 8 that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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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 the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

During the year ended December 31, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters.

•In February 2023, the CPUC approved a final decision, adopting without modification the Utility’s settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion. In January 2023, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million. In December 2022, the Utility filed the 2022 WMCE application requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion.

•In December 2022, OEIS issued the Utility’s 2022 safety certification.

•In December 2022, the CPUC approved a resolution authorizing the Utility’s exit from the EOEP.

•In December 2022, the CPUC issued a final decision in the Utility’s 2023 cost of capital proceeding, which sets the Utility’s ROE for 2023 at 10%.

•In November 2022, OEIS issued its final decision approving the Utility’s 2022 WMP, which the CPUC ratified in December.

•In November 2022, the CPUC issued a final decision in the Utility’s 2022 cost of capital proceeding. The decision retains the Utility’s cost of capital previously authorized in the 2020 cost of capital proceeding.

•In September 2022, the Utility filed an application with the CPUC regarding the separation of its non-nuclear generation assets into a stand-alone Utility subsidiary and the potential sale of a minority interest in the newly-formed subsidiary to one or more investors to be identified.

•In September 2022, the Governor of California signed SB 884, which authorizes and expedites OEIS and CPUC review of a 10-year undergrounding plan.

•In September 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon until 2030. In October 2022, the Utility executed a loan agreement with the DWR for up to $1.4 billion. In November, the DOE conditionally selected the Utility to receive funding of up to $1.1 billion as part of the Civil Nuclear Credit Program.

•In August 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, and in November 2022, PG&E Recovery Funding LLC issued approximately $983 million aggregate principal amount of Series 2022-A Senior Secured Recovery Bonds. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

•In March 2022, the CPUC approved a settlement agreement for the Utility’s 2018 CEMA application approving a total revenue requirement of $683 million plus interest for its expenses and capital costs, which is approximately 90% of the Utility’s total cost recovery request.

•In February 2022, a CPUC decision finding $7.5 billion of stress test costs eligible for securitization pursuant to SB 901 and a financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds in May and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds in July. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

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•In February 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines. In September 2022, the Utility submitted testimony updating the revenue requirement to reflect updates for escalation rates and federal tax law and guidance. As amended and updated, the Utility’s application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. In January 2023, the Utility filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding, for $183 million in expense and $127 million of capital expenditures. Also in January 2023, the CPUC approved a settlement pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2022, the Utility had recorded an aggregate amount of approximately $6.2 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Of these costs, approximately $856 million was authorized for recovery and accounted for as current, and $5.3 billion was accounted for as long term as of December 31, 2022. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to timely recover costs included in these applications.

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8, “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications,” and “Catastrophic Event Memorandum Account Application” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

Proceeding	Request	Status
2020 WMCE	Revenue requirement of approximately $1.28 billion	Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023.
2021 WMCE	Revenue requirement of approximately $1.47 billion	Partial settlement agreement to recover $721 million of revenue requirement filed January 2022. Settlement excludes VMBA’s $591 million revenue requirement.
2022 WMCE	Revenue requirement of approximately $1.36 billion	Filed December 15, 2022.
2018 CEMA	Revenue requirement of $763 million	Settlement agreement to recover $683 million plus interest approved March 2022.

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Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which excluded amounts disallowed as a result of the CPUC’s decision in the OII into the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”), and the 2018 Camp fire, consisted of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and were incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflected work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue included amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility’s proposed revenue requirement would be collected over a two-year period beginning in January 2023.

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery request of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of costs, such as employee business travel expenses and in-person training costs, that the Utility was able to avoid due to the pandemic.

On January 18, 2023, the Utility, TURN, and Cal Advocates filed a joint motion for approval of a settlement agreement, pursuant to which the Utility would receive a revenue requirement of $720.7 million. The settlement agreement does not address $591.9 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

2022 WMCE Application

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

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The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the 2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision.

The Utility has proposed a schedule that would call for a final decision by the CPUC in December 2023.

Catastrophic Event Memorandum Account Application

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought to recover CEMA-eligible costs through its WMCE applications.

In addition to the Utility’s responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to track these costs in the VMBA for the period beginning January 1, 2020.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented, commencing on October 1, 2019.

On March 17, 2022, the CPUC approved a settlement agreement authorizing the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement will be amortized over a 12-month period, which began on June 1, 2022.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on approved revenue requirements and possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications.

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The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

Rate Case	Request	Status
2023 GRC	Revenue requirement of $15.82 billion for 2023	A decision is scheduled for the third quarter of 2023.
2022 Cost of Capital	Leave cost of capital components at pre-2022 levels for 2022	Final decision issued November 2022, leaving the cost of capital components at pre-2022 levels for 2022. Intervenors filed application for rehearing in December 2022.
2023 Cost of Capital	Increase ROE to 11% and cost of debt to 4.31%	Final decision issued December 2022, adopting a 10% ROE. Intervenor filed application for rehearing in January 2023.
2015 GT&S	Revenue requirement of $416 million related to 2011-2014 capital expenditures subject to audit	Final decision issued July 2022 approving settlement to recover $356 million of revenue requirements.

2023 General Rate Case

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC (“the Original Application”). The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In a GRC, the CPUC approves annual revenue requirements for the first year (a “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”). In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation 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, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the Original Application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service.

Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application that revised and superseded the revenue requirement request in the Original Application. On September 6, 2022, the Utility submitted testimony updating the revenue requirement request in its 2023 GRC proceeding. The testimony reflected updates for escalation rates and federal tax law and guidance since the filing of the Original Application. On December 9, 2022, the Utility submitted a post-hearing reply brief. In the reply brief, the Utility updated the revenue requirement request due to the wildfire insurance settlement dated October 7, 2022 discussed below, stipulations with the parties regarding several disputed issues, and a reduction to the Utility’s forecast for wildfire system hardening mileage targets over the 2023 to 2026 rate case period.

As amended and updated, the Utility’s application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. The tables below compare the requested revenue requirements and rate base for the GRC period from 2023 through 2026 to those adopted for 2022 in the 2020 GRC and 2019 GT&S proceedings:

(in billions)	2022 (as adopted)		2023		2024		2025		2026
Requested revenue requirement	$	12.21	$	15.82	$	16.74	$	17.18	$	17.43
Requested weighted-average GRC rate base	39.21		50.41		55.39		59.56		63.68

Over the GRC period of 2023 through 2026, the Utility plans to make average annual capital investments of approximately $9.69 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

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On July 22, 2022, the Utility submitted a request for the second track of this proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $206 million in expenses and $129 million in capital expenditures, resulting in a proposed revenue requirement of approximately $241 million, most of which is proposed to be collected over a two-year period beginning August 1, 2023. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. The self-insurance will be funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected in rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. As a result, the Utility could collect the self-insurance amounts over a longer period than it makes wildfire-related payments. The settlement agreement includes a five percent deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

The Utility does not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7.

The CPUC’s schedule indicated a final decision on the first two tracks of this proceeding would be issued in the third quarter of 2023.

Cost of Capital Proceedings

2020 and 2022 Cost of Capital Applications

On December 19, 2019, the CPUC approved a final decision in the 2020 cost of capital application (the “2020 cost of capital application”), maintaining the Utility’s ROE at the 2019 level of 10.25% for the three-year period beginning January 1, 2020. The decision maintained the common equity component of the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking) at 52% and reduced its preferred stock component from 1% to 0.5%. The decision also approved the cost of debt requested by the Utility.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding. On October 28, 2021, the CPUC ruled that the Utility was required to comply with the cost of capital mechanism for 2022.

On November 3, 2022, the CPUC issued a final decision, finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. The final decision retains the cost of capital for 2022 previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility filed a response to the application for rehearing.

For more information regarding this proceeding, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

2023 Cost of Capital Application

On April 20, 2022, the Utility filed an application with the CPUC requesting that the CPUC authorize the Utility’s cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023 (the “2023 cost of capital application”).

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In its 2023 cost of capital application, the Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt.

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision.

The following table compares the currently authorized capital structure and rates of return with those adopted in the final decision for 2023, as corrected.

	2022 authorized by the 2022 Cost of Capital Application						2023 Cost of Capital decision
	Cost		Capital structure		Weighted cost		Cost		Capital structure		Weighted cost
Common equity	10.25	%	52.00	%	5.33	%	10.00	%	52.00	%	5.20	%
Preferred stock	5.52	%	0.50	%	0.03	%	5.52	%	0.50	%	0.03	%
Long-term debt	4.17	%	47.50	%	1.98	%	4.31	%	47.50	%	2.05	%
Weighted average cost of capital			100.00	%	7.34	%			100.00	%	7.28	%

For 2023, the Utility expects that the newly-adopted cost of capital will result in revenue requirement decreases of approximately $23 million for electric generation and distribution and $10 million for gas distribution operations, assuming 2022 authorized rate base amounts from the 2020 GRC decision. The revenues for the gas transmission and storage operations will decrease by approximately $7 million, assuming 2022 authorized rate base amounts from the 2019 GT&S decision. Actual revenue requirement changes resulting from the Utility’s requested ROE for the period beyond 2022 may differ from the amounts reflected above, pending the outcome of the 2023 GRC.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The Utility included an illustrative calculation using the period March 2021 to February 2022 with an adjustment to increase the rate by 153 basis points, which would result in an estimated $69 million increase in recovery of short-term financing costs associated with its recent balancing and memorandum account balances. The actual revenue requirement impact of the short-term debt proposal would differ depending on the final adjustment set each year and the recorded balances in the balancing and memorandum accounts. The decision deferred consideration of the proposal to a second phase of the proceeding.

The cost of capital that is approved in this proceeding is expected to be effective until December 31, 2025, unless the cost of capital adjustment mechanism is triggered. (For more information on the cost of capital adjustment mechanism, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.)

On January 18, 2023, an intervenor filed an application for rehearing of the final decision. On February 2, 2023, the Utility filed a response to the application for rehearing.

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of 2011 to 2014 capital spending in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit.

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On July 31, 2020, the Utility filed an application seeking recovery of $416 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. On July 14, 2022, the CPUC approved a final decision approving the settlement agreement, which resolved all issues in this proceeding and authorized a $356 million revenue requirement for the period of 2015 through 2022. Of this amount, $313 million of revenues for the period 2015 through 2021 will be amortized in rates over 60 months and $43 million associated with 2022 will be amortized in rates over 12 months beginning August 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application was included in test year 2023 rate base in the Utility’s consolidated 2023 GRC.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

On January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50-basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Ninth Circuit Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder.

On March 17, 2020, the FERC issued its order denying requests for rehearing that were previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals.

On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation. The order would extinguish the Utility’s refund obligations that might have been required under the TO16 and TO17 rate cases had the Ninth Circuit Court of Appeals not found in the FERC’s favor. On May 2, 2022, the CPUC filed a petition for panel rehearing of the order. On May 25, 2022, the Ninth Circuit Court of Appeals issued a decision denying the request for rehearing and the request for a rehearing en banc.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

On July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility’s continuing participation in the CAISO. 

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (1) impact of the Tax Act on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of December 31, 2022, the Utility had recorded approximately $258 million to Regulatory assets.

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On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding. On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

Aside from the ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

On July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation, and so the Utility was not obligated to make a refund to customers based on this matter. See “Transmission Owner Rate Cases for 2015 and 2016” above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

On October 1, 2018, the Utility filed its TO20 rate case with the FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the effective date for rate changes. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.

On March 31, 2020, the Utility filed a partial settlement with the FERC, which the FERC approved on August 17, 2020. On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the formula rate proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement established an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing by October 18, 2023 to be effective on January 1, 2024.

On December 30, 2020, the FERC approved the settlement without modification.

Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO20 rate case.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

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Other Regulatory Proceedings

Enhanced Oversight and Enforcement Process

In the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics. The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and OIIs and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

The Utility is unable to predict whether fines or penalties may be imposed, or other regulatory actions may be taken.

Vegetation Management

The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC’s resolution states that a step 1 triggering event had occurred because the Utility had “made insufficient progress toward approved safety or risk-driven investments related to its electric business.” The resolution found that, based on the CPUC’s evaluation of the Utility’s EVM work in 2020, the Utility was “not sufficiently prioritizing its Enhanced Vegetation Management (“EVM”) based on risk” and was “not making risk-driven investments.” The resolution also found that “less than five percent of the EVM work” the Utility completed in 2020 “was on the 20 highest risk power lines according to its own risk rankings.”

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s Executive Director on May 6, 2021, which was designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addressed the EVM situation that occurred in 2020 and provided a risk-informed EVM work plan for 2021. The Utility was required to update the information contained in the corrective action plan every 90 days, which it did.

On December 1, 2022, the CPUC issued a resolution authorizing the Utility’s exit from the EOEP.

Application for Post-Emergence SB 901 Securitization Transaction

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers through the creation of a corresponding customer credit trust, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a “securitization” refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

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On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. and approving a structure for the transaction. As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC’s existing jurisdiction, the decision adopted a transaction structure comprised of four elements: (1) an initial shareholder contribution of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

In addition, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires, which the CPUC subsequently granted on May 11, 2021.

On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. The financing order authorized the issuance of bonds through the end of 2022. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Application for Second AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. Pursuant to an earlier financing order issued by the CPUC authorizing the Utility’s initial application for AB 1054 securitization transaction, on November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.  The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC revenue requirements following the issuance of the recovery bonds. 

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million then pending in the 2020 WMCE proceeding.

On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million aggregate principal amount of Series 2022-A Senior Secured Recovery Bonds.

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2020-2022 Wildfire Mitigation Plan

The Utility’s 2022 WMP was submitted on February 25, 2022. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and reducing the impact of PSPS events. On November 10, 2022, OEIS approved the Utility’s 2022 WMP. On December 15, 2022, the CPUC ratified OEIS’s approval.

On December 5, 2022, OEIS issued its draft Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the draft ARC, OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets but found that the Utility failed to meet targets highly correlated with risk, failed to achieve critical stated objectives, and failed to sufficiently address risk on its system. Consequently, OEIS found the Utility did not substantially comply with the WMP during the 2020 compliance period. The Utility submitted comments on the draft ARC in December 2022. If the OEIS final ARC report maintains the finding that the Utility failed to substantially comply with its 2020 WMP, the Utility may seek judicial review. If the ARC finds that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate at this time whether they will incur a loss in connection with the ARC or the amount of any such loss, as OEIS has not issued the final ARC and because any penalty issued by CPUC depends upon a number of factors.

Electric Integrated Resource Planning and Related Procurement

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision required incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period from 2021 to 2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision required that at least 50% of LSEs resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directed the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision.

On June 30, 2021, the CPUC issued a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirement of once-through-cooling natural gas plants in Southern California and the possible retirement of Diablo Canyon by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs. See “Extension of Diablo Canyon Operations” below. The decision set procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision set the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

On April 21, 2022, the CPUC approved a group of nine long-term RA agreements to meet a portion of the Utility’s procurement requirements under the CPUC’s mid-term reliability decision. The agreements are each for a term of 15 years and collectively expected to supply 1,598.7 MW of lithium-ion energy storage capacity with some projects expected to be operational in 2023 and others in 2024.

OIR to Revisit Net Energy Metering Tariffs

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers.

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On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On February 2, 2023, the Utility filed a response to the application for rehearing.

Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter.

On December 13, 2022, the Utility filed applications with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation.

On January 20, 2023, the CPUC issued a scoping memo pursuant to which a PD would be issued by November 2023.

Self-Reports to the CPUC

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, accordingly, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. In addition to its plan to complete the intrusive tests by September 30, 2023, the Utility is performing an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues.

The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

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Order Instituting an Investigation into PG&E Corporation’s and 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 “Safety Culture OII”). 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.

On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’s rate of return or ROE to safety performance metrics.

On September 4, 2020, the administrative law judge issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture and to address any relevant issues that arise, with the CPUC’s consultant continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.

Extension of Diablo Canyon Operations

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility would continue to operate Diablo Canyon on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs would be responsible for the cost of extended operations. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations, which is in addition to the amount discussed in “Assembly Bill 180”, below. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances. On October 18, 2022, the Utility executed the loan agreement with the DWR.

On September 2, 2022, the Utility applied for federal funding through the DOE’s Civil Nuclear Credit Program. On November 17, 2022, the DOE conditionally selected the Utility to receive funding of up to $1.1 billion as part of the program. Final terms are subject to negotiation and finalization by the DOE. SB 846 provides that within 180 days of the filing of the DOE application, the CEC, in consultation with the CAISO and the CPUC, shall make a determination in a public process of whether the state’s electricity forecasts for the calendar years from 2024 through 2030 show potential for reliability deficiencies if Diablo Canyon operations are not extended beyond 2025 and whether extending operations of Diablo Canyon until 2030 is prudent to ensure reliability in light of any potential for supply deficiency. During the quarter ended December 31, 2022, the Utility adjusted the ARO to reflect extended operations of Diablo Canyon through 2030. However, the Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

During the period prior to extended operations, the bill authorizes a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon. The performance-based disbursement will be paid from the loan proceeds authorized by SB 846 and is contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The performance-based disbursement cannot be realized as shareholder profits or paid out as dividends.

During the period of extended operations and in lieu of the traditional rate-based return on investment, the bill provides for a fixed payment of $50 million, in 2022 dollars, for each of Diablo Canyon’s Unit 1 and Unit 2 for each year of extended operations to be recovered from customers of all CPUC-jurisdictional LSEs, which is potentially subject to adjustment downward in the event of extended unplanned outages. In addition, the bill authorizes a volumetric payment totaling $13, in 2022 dollars, for each MWh generated by Diablo Canyon during the period of extended operations, with the first half recovered from all CPUC-jurisdictional LSEs and the second half from customers in the Utility’s service area. The amount of the fixed and volumetric payments will be adjusted annually by the CPUC using CPUC-approved escalation methodologies and adjustment factors. The volumetric payment cannot be realized as shareholder profits or paid out as dividends, to the extent it is not needed for Diablo Canyon. The legislation includes language that limits use of the volumetric payment to investments in the system and for customers that address critical state priorities.

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The CPUC has initiated a rulemaking proceeding in January 2023 to develop a new mechanism to recover costs from customers of all CPUC-jurisdictional LSEs for the continued operation of Diablo Canyon and to address other issues associated with continued operation, including cost responsibility if Diablo Canyon is unable to operate. The legislation also established a $300 million Liquidated Damages Balancing Account (“LDBA”) to be funded over time by all CPUC-jurisdictional customers. The LDBA provides a source for paying for replacement power costs, if incurred, due to unplanned outages at Diablo Canyon as a result of the Utility’s failure to meet the CPUC’s reasonable-manager standard.

The key remaining steps to continued operations include NRC license renewal and approval from California state agencies. If either is not received, the Utility would retire Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC. On October 31, 2022, the Utility requested that the NRC resume its review of a license renewal application the Utility voluntarily withdrew and terminated in 2018 or else grant an exemption to permit operations to continue at Diablo Canyon after the expiration of each of its current operating licenses and until the NRC completes its review of the license renewal application. On January 24, 2023, the NRC staff declined to resume its review of the previously-withdrawn application and directed the Utility to submit a new application for license renewal, which the Utility expects to do by the end of 2023. The NRC staff has stated that it will provide a response to the Utility’s request for an exemption in March 2023. Consistent with SB 846, the CPUC, the CEC, California State Lands Commission, California Coastal Commission, and other state agencies will need to determine that extended operations represent an appropriate path to meet California’s reliability, affordability, and environmental goals.

LEGISLATIVE AND REGULATORY INITIATIVES

Assembly Bill 180

On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation.

Assembly Bill 205

On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs. The Utility received approximately $200 million in November 2022 to reduce the amounts owed by customer accounts in arrears. The amount of funding was determined by the California Department of Community Services and Development, which is the agency responsible for administering the CAPP.

Senate Bill 846

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. For more information, see “Extension of Diablo Canyon Operations” above.

Senate Bill 884

On September 30, 2022, the Governor of California signed SB 884, which authorizes and expedites OEIS and CPUC review of a 10-year undergrounding plan. Under SB 884, large electrical corporations may submit 10-year plans for undergrounding distribution infrastructure in Tier 2 or 3 HFTDs or rebuild areas to OEIS. The plan must include an evaluation of project costs, projected economic benefits over the life of the assets, and any cost-containment assumptions, including the economies of scale necessary to reduce wildfire risk and mitigation costs and establish a sustainable supply chain. OEIS will have up to nine months to review and approve or deny the plan, and then the CPUC will have up to nine months to review and approve or deny the plan, including its costs.

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Inflation Reduction Act

On August 16, 2022, the President of the United States signed the Inflation Reduction Act. The Inflation Reduction Act includes a 15% corporate alternative minimum tax (“CAMT”) on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for renewable and clean energy sources. Many aspects of the Inflation Reduction Act, including the CAMT, remain uncertain and the U.S. Department of the Treasury and the Internal Revenue Service have been granted broad authority to enact regulations implementing its provisions. Depending on the guidance issued, PG&E Corporation and the Utility’s federal income tax liability could increase substantially. PG&E Corporation and the Utility continue to evaluate the impact of the law and its potential implications.

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 substances; the reporting and reduction of carbon dioxide 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, “Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 16 of the Notes to the Consolidated 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.

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. 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. 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 do 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 in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $3 million and $5 million at December 31, 2022 and 2021, respectively. See Note 11 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. At December 31, 2022 and 2021, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $54 million and $76 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

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Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, 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 and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, 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. Security 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). Security or performance assurance may be required from the Utility or counterparties when current net receivables or payables and exposure exceed contractually specified limits.

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

	Exposure (1) (in millions)		Number of Wholesale Customers or Counterparties >10%	Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions)
December 31, 2022	$	814	1	$	162
December 31, 2021	$	570	1	$	63

(1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

CRITICAL ACCOUNTING ESTIMATES

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 estimates 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 estimates and their key characteristics are outlined below.

Contributions to the Wildfire Fund

The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service area classified as HFTDs and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).

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On the Emergence Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2021 and 2022, the Utility made its third and fourth annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2022, PG&E Corporation and the Utility have six remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below.

As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in current assets - Wildfire Fund asset, and $4.8 billion in non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Initial use of five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, would have resulted in a six year amortization period. As of December 31, 2022, a 5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by five years assuming greater effectiveness and would decrease the amortization period by four years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by participating electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly and upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such acceleration of the amortization of the asset could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service area. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is unknown, which may in the future be determined to be covered by the Wildfire Fund. As of December 31, 2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire. PG&E Corporation and the Utility recorded $6 million and $43 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2022 and 2021, respectively.

For more information, see “Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 and “Wildfire Fund under AB 1054” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Loss Contingencies

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

Wildfire-Related Liabilities

PG&E Corporation and the Utility are subject to potential liabilities related to wildfires.  PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

Potential liabilities related to wildfires depend on various factors, including negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation or the Utility. For example, the Utility’s wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages.

The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires.  See Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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 provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. Actual results may differ materially from these estimates and assumptions. See Note 15 and Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur and they 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.  Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former MGP sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has a program related to certain former MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.

As of December 31, 2022 and 2021, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each. The Utility’s undiscounted future costs could increase to as much as $2.3 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

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. Despite the ongoing losses related to wildfires (see Note 15 of the Notes to the Consolidated Financial Statements in Item 8), there is no actual or anticipated change in the cost-of-service regulation of the Utility’s operations. Therefore, the Utility continues to apply the accounting ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 3 as well as Note 4 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2022, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $20.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $20.4 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. 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.

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A portion of the Utility’s regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account, and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 pandemic. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. For more information, see “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account” and “Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications” above.

Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2022, the SB 901 regulatory asset was approximately $5.4 billion.

In addition, regulatory accounting standards require recognition of a loss 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’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. 

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 3 and 4 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, 2022, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.9 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.

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 eligible retirees 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 through rates. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

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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. See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

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 2023 was 6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 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 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 projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of 6.1% compares to a ten-year actual return of 5.8%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 848 Aa-grade non-callable bonds at December 31, 2022. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

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

(in millions)	Increase (Decrease) in Assumption		Increase in 2022 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2022
Discount rate	(0.50)	%	$	5	$	1,038
Rate of return on plan assets	(0.50)	%	108		—
Rate of increase in compensation	0.50	%	44		207

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

(in millions)	Increase (Decrease) in Assumption		Increase in 2022 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2022
Health care cost trend rate	0.50	%	$	8	$	38
Discount rate	(0.50)	%	11		81
Rate of return on plan assets	(0.50)	%	15		—

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

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 11: Derivatives and Note 12: 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,
	2022		2021		2020
Operating Revenues
Electric	$	15,060	$	15,131	$	13,858
Natural gas	6,620		5,511		4,611
Total operating revenues	21,680		20,642		18,469
Operating Expenses
Cost of electricity	2,756		3,232		3,116
Cost of natural gas	2,100		1,149		782
Operating and maintenance	9,809		10,200		8,684
SB 901 securitization charges, net	608		—		—
Wildfire-related claims, net of recoveries	237		258		251
Wildfire Fund expense	477		517		413
Depreciation, amortization, and decommissioning	3,856		3,403		3,468
Total operating expenses	19,843		18,759		16,714
Operating Income	1,837		1,883		1,755
Interest income	162		20		39
Interest expense	(1,917)		(1,601)		(1,260)
Other income, net	394		457		483
Reorganization items, net	—		(11)		(1,959)
Income Before Income Taxes	476		748		(942)
Income tax provision (benefit)	(1,338)		836		362
Net Income (Loss)	1,814		(88)		(1,304)
Preferred stock dividend requirement of subsidiary	14		14		14
Income (Loss) Attributable to Common Shareholders	$	1,800	$	(102)	$	(1,318)
Weighted Average Common Shares Outstanding, Basic	1,987		1,985		1,257
Weighted Average Common Shares Outstanding, Diluted	2,132		1,985		1,257
Net Income (Loss) Per Common Share, Basic	$	0.91	$	(0.05)	$	(1.05)
Net Income (Loss) Per Common Share, Diluted	$	0.84	$	(0.05)	$	(1.05)

See accompanying Notes to the Consolidated Financial Statements.

97

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2022		2021		2020
Net Income (Loss)	$	1,814	$	(88)	$	(1,304)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	21		7		(17)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)	(6)		—		—
Total other comprehensive income (loss)	15		7		(17)
Comprehensive Income (Loss)	1,829		(81)		(1,321)
Preferred stock dividend requirement of subsidiary	14		14		14
Comprehensive Income (Loss) Attributable to Common Shareholders	$	1,815	$	(95)	$	(1,335)

See accompanying Notes to the Consolidated Financial Statements.

98

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2022		2021
ASSETS
Current Assets
Cash and cash equivalents	$	734	$	291
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	213		16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645		2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304		1,207
Regulatory balancing accounts	3,264		2,999
Other	1,624		1,784
Regulatory assets	296		496
Inventories
Gas stored underground and fuel oil	91		44
Materials and supplies	751		552
Wildfire Fund asset	460		461
Other	1,433		882
Total current assets	12,815		11,077
Property, Plant, and Equipment
Electric	74,772		69,482
Gas	28,226		25,979
Construction work in progress	4,137		3,479
Financing lease and other	19		20
Total property, plant, and equipment	107,154		98,960
Accumulated depreciation	(30,946)		(29,134)
Net property, plant, and equipment	76,208		69,826
Other Noncurrent Assets
Regulatory assets	16,443		9,207
Customer credit trust	745		—
Nuclear decommissioning trusts	3,297		3,798
Operating lease right of use asset	1,311		1,234
Wildfire Fund asset	4,847		5,313
Income taxes receivable	9		9
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)	2,969		2,863
Total other noncurrent assets	29,621		22,424
TOTAL ASSETS	$	118,644	$	103,327

See accompanying Notes to the Consolidated Financial Statements.

99

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2022		2021
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,055	$	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268		4,481
Accounts payable
Trade creditors	2,888		2,855
Regulatory balancing accounts	1,658		1,121
Other	778		679
Operating lease liabilities	231		468
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	626		481
Wildfire-related claims	1,912		2,722
Other	3,372		2,436
Total current liabilities	15,788		17,427
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	47,742		38,225
Regulatory liabilities	17,630		11,999
Pension and other postretirement benefits	231		860
Asset retirement obligations	5,912		5,298
Deferred income taxes	2,732		3,177
Operating lease liabilities	1,243		810
Other	4,291		4,308
Total noncurrent liabilities	79,781		64,677
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates	32,887		35,129
Treasury stock, at cost; 247,743,590 and 477,743,590 shares at respective dates	(2,517)		(4,854)
Reinvested earnings	(7,542)		(9,284)
Accumulated other comprehensive loss	(5)		(20)
Total shareholders’ equity	22,823		20,971
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	23,075		21,223
TOTAL LIABILITIES AND EQUITY	$	118,644	$	103,327

See accompanying Notes to the Consolidated Financial Statements.

100

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2022		2021		2020
Cash Flows from Operating Activities
Net income (loss)	$	1,814	$	(88)	$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,856		3,403		3,468
Bad Debt Expense	143		154		150
Allowance for equity funds used during construction	(184)		(133)		(140)
Deferred income taxes and tax credits, net	(452)		1,783		1,097
Reorganization items, net (Note 2)	—		(73)		1,458
Wildfire fund expense	477		517		413
Disallowed capital expenditures	15		—		17
Other	517		248		249
Effect of changes in operating assets and liabilities:
Accounts receivable	(757)		(589)		(1,182)
Wildfire-related insurance receivable	453		(723)		1,564
Inventories	(246)		(32)		6
Accounts payable	627		117		58
Wildfire-related claims	(810)		472		(16,525)
Other current assets and liabilities	17		244		(1,079)
Regulatory assets, liabilities, and balancing accounts, net	(1,131)		(2,266)		(2,451)
Liabilities subject to compromise	—		—		413
Contributions to Wildfire fund	(193)		(193)		(5,200)
Other noncurrent assets and liabilities	(425)		(579)		(142)
Net cash provided by (used in) operating activities	3,721		2,262		(19,130)
Cash Flows from Investing Activities
Capital expenditures	(9,584)		(7,689)		(7,690)
Proceeds from sale of the SFGO	—		749		—
Proceeds from sales and maturities of nuclear decommissioning trust    investments	3,316		1,678		1,518
Purchases of nuclear decommissioning trust investments	(3,208)		(1,702)		(1,590)
Proceeds from sales and maturities of customer credit trust investments	250		—		—
Purchases of customer credit trust investments	(1,022)		—		—
Other	34		59		14
Net cash used in investing activities	(10,214)		(6,905)		(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	—		—		500
Repayments of debtor-in-possession credit facility	—		—		(2,000)
Debtor-in-possession credit facility debt issuance costs	—		—		(6)
Bridge facility financing fees	—		—		(73)
Borrowings under credit facilities	10,130		9,730		8,554
Repayments under credit facilities	(9,750)		(9,976)		(3,949)
Credit facilities financing fees	—		(9)		(22)

101

Short-term debt financing, net of issuance costs of $0, $1, and $2 at    respective dates	—		300		1,448
Short-term debt matured	(300)		(1,450)		—
Proceeds from issuance of long-term debt, net of premium, discount and    issuance costs of $29, $33, and $178 at respective dates	4,271		4,624		13,497
Repayment of long-term debt	(5,968)		(87)		(764)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees    of $36, $0 and $0 at respective dates	7,464		—		—
Repayment of SB 901 recovery bonds	(33)		—		—
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees    of $11, $10 and $0 at respective dates	972		850		—
Repayment of AB 1054 recovery bonds	(18)		—		—
Proceeds from DWR loan, net of performance based incentives earned of    $38, $0, and $0 at respective dates	312		—		—
Proceeds from sale of future revenue from transmission tower license    sales, net of fees	—		370		—
Exchanged debt financing fees	—		—		(103)
Common stock issued	—		—		7,582
Equity Units issued	—		—		1,304
Other	53		(29)		(40)
Net cash provided by financing activities	7,133		4,323		25,928
Net change in cash, cash equivalents, and restricted cash	640		(320)		(950)
Cash, cash equivalents, and restricted cash at January 1	307		627		1,577
Cash, cash equivalents, and restricted cash at December 31	$	947	$	307	$	627
Less: Restricted cash and restricted cash equivalents	(213)		(16)		(143)
Cash and cash equivalents at December 31	$	734	$	291	$	484

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(1,607)	$	(1,404)	$	(1,563)
Income taxes, net	—		99		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,174	$	1,311	$	515
Operating lease liabilities arising from obtaining ROU assets	529		100		13
Common stock issued in satisfaction of liabilities	—		—		8,276
Changes to PG&E Corporation common stock and treasury stock in    connection with the Share Exchange and Tax Matters Agreement	(2,337)		4,854		—

See accompanying Notes to the Consolidated Financial Statements.

102

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Common Stock			Treasury Stock			Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock  of Subsidiary		Total Equity
	Shares	Amount		Shares	Amount
Balance at December 31, 2019	529,236,741	$	13,038	—	$	—	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Net loss	—	—		—	—		(1,304)		—		(1,304)		—		(1,304)
Other comprehensive loss	—	—		—	—		—		(17)		(17)		—		(17)
Common stock issued, net	1,455,441,932	15,854		—	—		—		—		15,854		—		15,854
Equity units issued	—	1,304		—	—		—		—		1,304		—		1,304
Stock-based compensation amortization	—	28		—	—		—		—		28		—		28
Balance at December 31, 2020	1,984,678,673	$	30,224	—	$	—	$	(9,196)	$	(27)	$	21,001	$	252	$	21,253
Net loss	—	—		—	—		(88)		—		(88)		—		(88)
Other comprehensive income	—	—		—	—		—		7		7		—		7
Common stock issued, net (1)	721,867	4,854		—	—		—		—		4,854		—		4,854
Treasury stock acquired	—	—		477,743,590	(4,854)		—		—		(4,854)				(4,854)
Stock-based compensation amortization	—	51		—	—		—		—		51		—		51
Balance at December 31, 2021	1,985,400,540	$	35,129	477,743,590	$	(4,854)	$	(9,284)	$	(20)	$	20,971	$	252	$	21,223
Net income	—	—		—	—		1,814		—		1,814		—		1,814
Other comprehensive income	—	—		—	—		—		15		15		—		15
Common stock issued, net	2,384,408	(2,337)		—	—		—		—		(2,337)		—		(2,337)
Treasury stock disposition	—	—		(230,000,000)	2,337		—		—		2,337		—		2,337
Stock-based compensation amortization	—	95		—	—		—		—		95		—		95
Preferred stock dividend requirement of subsidiary in arrears	—	—		—	—		(59)		—		(59)		—		(59)
Preferred stock dividend requirement of subsidiary	—	—		—	—		(13)		—		(13)		—		(13)
Balance at December 31, 2022	1,987,784,948	$	32,887	247,743,590	$	(2,517)	$	(7,542)	$	(5)	$	22,823	$	252	$	23,075

(1) Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K .

See accompanying Notes to the Consolidated Financial Statements.

103

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2022		2021		2020
Operating Revenues
Electric	$	15,060	$	15,131	$	13,858
Natural gas	6,620		5,511		4,611
Total operating revenues	21,680		20,642		18,469
Operating Expenses
Cost of electricity	2,756		3,232		3,116
Cost of natural gas	2,100		1,149		782
Operating and maintenance	9,725		10,194		8,707
SB 901 securitization charges, net	608		—		—
Wildfire-related claims, net of recoveries	237		258		251
Wildfire Fund expense	477		517		413
Depreciation, amortization, and decommissioning	3,856		3,403		3,469
Total operating expenses	19,759		18,753		16,738
Operating Income	1,921		1,889		1,731
Interest income	162		22		39
Interest expense	(1,658)		(1,373)		(1,111)
Other income, net	595		512		470
Reorganization items, net	—		(12)		(310)
Income Before Income Taxes	1,020		1,038		819
Income tax provision (benefit)	(1,206)		900		408
Net Income	2,226		138		411
Preferred stock dividend requirement	14		14		14
Income Attributable to Common Stock	$	2,212	$	124	$	397

See accompanying Notes to the Consolidated Financial Statements.

104

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2022		2021		2020
Net Income	$	2,226	$	138	$	411
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes     of $2, $1, and $2, at respective dates)	6		(4)		(6)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)	(5)		—		—
Total other comprehensive income (loss)	1		(4)		(6)
Comprehensive Income	$	2,227	$	134	$	405

See accompanying Notes to the Consolidated Financial Statements.

105

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance At December 31,
	2022		2021
ASSETS
Current Assets
Cash and cash equivalents	$	609	$	165
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	213		16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645		2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304		1,207
Regulatory balancing accounts	3,264		2,999
Other	1,633		1,932
Regulatory assets	296		496
Inventories
Gas stored underground and fuel oil	91		44
Materials and supplies	751		552
Wildfire Fund asset	460		461
Other	1,421		869
Total current assets	12,687		11,086
Property, Plant, and Equipment
Electric	74,772		69,482
Gas	28,226		25,979
Construction work in progress	4,137		3,480
Financing lease	18		18
Total property, plant, and equipment	107,153		98,959
Accumulated depreciation	(30,946)		(29,131)
Net property, plant, and equipment	76,207		69,828
Other Noncurrent Assets
Regulatory assets	16,443		9,207
Customer credit trust	745		—
Nuclear decommissioning trusts	3,297		3,798
Operating lease right of use asset	1,311		1,232
Wildfire Fund asset	4,847		5,313
Income taxes receivable	7		7
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)	2,834		2,706
Total other noncurrent assets	29,484		22,263
TOTAL ASSETS	$	118,378	$	103,177

See accompanying Notes to the Consolidated Financial Statements.

106

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance At December 31,
	2022		2021
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	2,055	$	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,241		4,455
Accounts payable
Trade creditors	2,886		2,853
Regulatory balancing accounts	1,658		1,121
Other	747		648
Operating lease liabilities	231		467
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	573		430
Wildfire-related claims	1,912		2,722
Other	3,067		2,430
Total current liabilities	15,370		17,310
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	43,155		33,632
Regulatory liabilities	17,630		11,999
Pension and other postretirement benefits	160		764
Asset retirement obligations	5,912		5,298
Deferred income taxes	3,090		3,409
Operating lease liabilities	1,243		810
Other	4,334		4,345
Total noncurrent liabilities	75,524		60,257
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	29,280		28,286
Reinvested earnings	(3,368)		(4,247)
Accumulated other comprehensive loss	(8)		(9)
Total shareholders’ equity	27,484		25,610
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	118,378	$	103,177

See accompanying Notes to the Consolidated Financial Statements.

107

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2022		2021		2020
Cash Flows from Operating Activities
Net income	$	2,226	$	138	$	411
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,856		3,403		3,469
Bad Debt Expense	143		154		150
Allowance for equity funds used during construction	(184)		(133)		(140)
Deferred income taxes and tax credits, net	(319)		1,846		1,141
Reorganization items, net (Note 2)	—		(41)		(90)
Wildfire Fund expense	477		517		413
Disallowed capital expenditures	15		—		17
Other	102		172		220
Effect of changes in operating assets and liabilities:
Accounts receivable	(763)		(584)		(1,160)
Wildfire-related insurance receivable	453		(723)		1,564
Inventories	(246)		(32)		6
Accounts payable	627		44		(24)
Wildfire-related claims	(810)		472		(16,525)
Other current assets and liabilities	16		251		(1,141)
Regulatory assets, liabilities, and balancing accounts, net	(1,131)		(2,266)		(2,451)
Liabilities subject to compromise	—		—		401
Contributions to Wildfire Fund	(193)		(193)		(5,200)
Other noncurrent assets and liabilities	(438)		(577)		(108)
Net cash provided by (used in) operating activities	3,831		2,448		(19,047)
Cash Flows from Investing Activities
Capital expenditures	(9,584)		(7,689)		(7,690)
Proceeds from sale of the SFGO	—		749		—
Proceeds from sales and maturities of nuclear decommissioning trust    investments	3,316		1,678		1,518
Purchases of nuclear decommissioning trust investments	(3,208)		(1,702)		(1,590)
Proceeds from sales and maturities of customer credit trust investments	250		—		—
Purchases of customer credit trust investments	(1,022)		—		—
Proceeds from (repayments of) intercompany note to PG&E Corporation	145		(145)		—
Other	34		59		14
Net cash used in investing activities	(10,069)		(7,050)		(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	—		—		500
Repayments of debtor-in-possession credit facility	—		—		(2,000)
Debtor-in-possession credit facility debt issuance costs	—		—		(6)
Bridge facility financing fees	—		—		(33)
Borrowings under credit facilities	10,130		9,730		8,554
Repayments under credit facilities	(9,750)		(9,976)		(3,949)

108

Credit facilities financing fees	—		(9)		(22)
Short-term debt financing, net of issuance costs of $0, $1, and $2 at    respective dates	—		300		1,448
Short-term debt matured	(300)		(1,450)		—
Proceeds from issuance of long-term debt, net of premium, discount and    issuance costs of $29, $33, and $88 at respective dates	4,271		4,624		8,837
Repayment of long-term debt	(5,941)		(59)		(100)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees    of $36, $0 and $0 at respective dates	7,464		—		—
Repayment of SB 901 recovery bonds	(33)		—		—
Proceeds from AB 1054 recovery bonds, net issuance costs of $11, $10,    and $0 at respective dates	972		850		—
Repayment of AB 1054 recovery bonds	(18)		—		—
Proceeds from DWR loan, net of performance based incentives earned of    $38, $0, and $0 at respective dates	312		—		—
Proceeds from sale of future revenue from transmission tower license    sales, net of fees	—		370		—
Exchanged debt financing fees	—		—		(103)
Preferred stock dividends paid	(70)		—		—
Common stock dividends paid	(1,275)		—		—
Equity contribution from PG&E Corporation	994		—		12,986
Other	123		(1)		(42)
Net cash provided by financing activities	6,879		4,379		26,070
Net change in cash, cash equivalents, and restricted cash	641		(223)		(725)
Cash, cash equivalents, and restricted cash at January 1	181		404		1,129
Cash, cash equivalents, and restricted cash at December 31	$	822	$	181	$	404
Less: Restricted cash and restricted cash equivalents	(213)		(16)		(143)
Cash and cash equivalents at December 31	$	609	$	165	$	261

 

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(1,374)	$	(1,198)	$	(1,458)
Income taxes, net	—		99		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,174	$	1,311	$	515
Operating lease liabilities arising from obtaining ROU assets	529		100		13
Common stock equity infusion from PG&E Corporation used to satisfy    liabilities	—		—		6,750

 See accompanying Notes to the Consolidated Financial Statements.

109

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2019	$	258	$	1,322	$	8,550	$	(4,796)	$	1	$	5,335
Net income	—		—		—		411		—		411
Other comprehensive loss	—		—		—		—		(6)		(6)
Equity contribution	—		—		19,736		—		—		19,736
Balance at December 31, 2020	$	258	$	1,322	$	28,286	$	(4,385)	$	(5)	$	25,476
Net income	—		—		—		138		—		138
Other comprehensive loss	—		—		—		—		(4)		(4)
Balance at December 31, 2021	$	258	$	1,322	$	28,286	$	(4,247)	$	(9)	$	25,610
Net income	—		—		—		2,226		—		2,226
Other comprehensive income	—		—		—		—		1		1
Equity contribution	—		—		994		—		—		994
Preferred stock dividend requirement in arrears	—		—		—		(59)		—		(59)
Preferred stock dividend requirement	—		—		—		(13)		—		(13)
Common stock dividend	—		—		—		(1,275)		—		(1,275)
Balance at December 31, 2022	$	258	$	1,322	$	29,280	$	(3,368)	$	(8)	$	27,484

See accompanying Notes to the Consolidated Financial Statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

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 assess financial 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, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan 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, results of operations, liquidity, and cash flows during the period in which such change occurred.

NOTE 2: BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Ad Hoc Committee of Holders of Trade Claims (the “Trade Committee”). The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On September 12, 2022, the Utility filed a petition for en banc review, which was denied on October 5, 2022. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the post-petition interest matter, but the amount of that loss is not reasonably estimable at this time. If the Ninth Circuit Court of Appeals decision is not reversed, then the matter would be remanded to the Bankruptcy Court to evaluate the rate of interest for each individual contract, the conditions under which the contract rate applies, and whether payment of interest under state law would be warranted for each contract and claimant. These proceedings therefore will require extensive discovery and motion practice before the Bankruptcy Court with respect to each of these claims on a variety of contractual issues and equitable considerations. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings or any further appeals.

Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.

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Unresolved Chapter 11 Claims

PG&E Corporation and the Utility have received over 100,000 proofs of claim since January 29, 2019, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and the Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims, including asserted litigation claims, trade creditor claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets.

Holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 15 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 15 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims that were subject to certain defenses which allowed PG&E Corporation and the Utility to file objections expunging those claims on an omnibus basis, PG&E Corporation and the Utility are working to resolve disputed claims, including Subordinated Debt Claims and HoldCo Rescission or Damage Claims. By order of the Bankruptcy Court, the current deadline for PG&E Corporation and the Utility to object to claims is June 20, 2023.

NOTE 3: 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 through 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.

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Cash, Cash Equivalents, and Restricted Cash

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. As of December 31, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

Revenue Recognition

Revenue from Contracts with Customers

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. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. 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, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. 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. As a result, these differences have no impact on net income.

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The following table presents the Utility’s revenues disaggregated by type of customer:

	Year Ended December 31,
(in millions)	2022		2021
Electric
Revenue from contracts with customers
Residential	$	6,130	$	6,089
Commercial	5,416		5,042
Industrial	1,626		1,493
Agricultural	1,830		1,565
Public street and highway lighting	77		73
Other, net (1)	(247)		(84)
Total revenue from contracts with customers - electric	14,832		14,178
Regulatory balancing accounts (2)	228		953
Total electric operating revenue	$	15,060	$	15,131
Natural gas
Revenue from contracts with customers
Residential	$	3,353	$	2,759
Commercial	1,005		713
Transportation service only	1,534		1,346
Other, net (1)	163		140
Total revenue from contracts with customers - gas	6,055		4,958
Regulatory balancing accounts (2)	565		553
Total natural gas operating revenue	6,620		5,511
Total operating revenues	$	21,680	$	20,642

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022.

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PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of December 31, 2022, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

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.

Inventories

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, 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.

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

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2022		2021
Electricity generating facilities (1)	5 to 75	$	11,781	$	11,217
Electricity distribution facilities	10 to 70	41,061		37,723
Electricity transmission facilities	15 to 75	16,413		15,516
Natural gas distribution facilities	20 to 60	15,366		14,100
Natural gas transmission and storage facilities	5 to 66	9,859		9,067
Financing lease		18		18
Construction work in progress		4,137		3,480
General plant and other	5 to 50	8,518		7,838
Total property, plant, and equipment		107,153		98,959
Accumulated depreciation		(30,946)		(29,131)
Net property, plant, and equipment (2)		$	76,207	$	69,828

(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 16 below.

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(2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 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, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020.  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 cost 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 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 $81 million and $184 million during 2022, $56 million and $133 million during 2021, and $35 million and $140 million during 2020.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations:

(in millions)	2022		2021
ARO liability at beginning of year	$	5,298	$	6,412
Liabilities incurred	134		—
Revision in estimated cash flows	325		(1,378)
Accretion	213		287
Liabilities settled	(58)		(23)
ARO liability at end of year	$	5,912	$	5,298

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. For more information, see Note 4 below.

The Utility has not recorded a liability related to certain AROs 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, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

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To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 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 through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020.

The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022.

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.

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 through rates and are held in trusts until authorized for release by the CPUC.

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The Utility classifies its debt 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 to or recoverable from, respectively, 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.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred.

Senate Bill 846

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE's Civil Nuclear Credit Program” below). Under the loan agreement, the DWR will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements.

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U.S. DOE’s Civil Nuclear Credit Program

On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense on the Consolidated Statements of Income as eligible costs are incurred.

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.  

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

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SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below.

Non-Consolidated VIEs

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 as of December 31, 2022, 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 or 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 as of December 31, 2022, it did not consolidate any of them.

Contributions to the Wildfire Fund Established Pursuant to AB 1054

PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

PG&E Corporation and the Utility evaluate and, where appropriate, update all assumptions quarterly. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire. During the year ended December 31, 2022, PG&E Corporation and the Utility updated assumptions related to the mitigation effectiveness and historical fire loss dataset to align with the risk modeling within the 2022 WMP. These updates did not change the estimated period of coverage, which continues to be 15 years from the inception of the Wildfire Fund.

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As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in Current assets - Wildfire Fund asset, and $4.8 billion in Non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. As of December 31, 2022, PG&E Corporation and the Utility had recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 15 below.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 10, “Derivatives” in Note 11, “Fair Value Measurements” in Note 12, and “Contingencies and Commitments” in Notes 15 and 16 below.

Voluntary Separation Program

In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income.

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, 2022 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassifications:
Loss on investments (net of taxes of $0, $0 and $3, respectively)	—		—		(6)		(6)
Unrecognized net actuarial gain (net of taxes of $102, $99 and $0, respectively)	263		(255)		—		8
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively)	(242)		255		—		13
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1, $2 and $0, respectively) (1)	(3)		5		—		2
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively) (1)	1		(29)		—		(28)
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1)	2		24		—		26
Net current period other comprehensive income (loss)	21		—		(6)		15
Ending balance	$	(12)	$	18	$	(6)	$	—

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 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, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively)(1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 below for additional details.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2022 and 2021.

For the years ended December 31, 2022 and 2021, the Utility made total cash payments, including fixed and variable, of $2.3 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements and the Oakland lease. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 16 below.

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PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. Property arrangements primarily consist of an office lease agreement for the Lakeside Building. On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease began on April 8, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). On February 6, 2023, the process of subdividing the real estate was completed. If the option is exercised pursuant to the terms of the existing agreement then the Purchase Price would be paid in or around July 2023.

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2022, approximately 488,000 rentable square feet of the leased premises has been made available for use by the Utility. The Utility has recorded approximately $535 million in Operating lease right of use assets, approximately $214 million of leasehold improvements, which includes approximately $137 million that was provided to the Utility as lease incentives, and approximately $672 million in noncurrent Operating lease liabilities in the Consolidated Financial Statements related to the Lease.

In January 2023, approximately 110,000 of additional rentable square feet was made available for use by the Utility.

At December 31, 2022 and 2021, the Utility’s operating leases had a weighted average remaining lease term of 19.6 years and 6.04 years and a weighted average discount rate of 6.5% and 6.1%, respectively.

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:

	Year Ended December 31,
(in millions)	2022		2021
Operating lease fixed cost	$	500	$	578
Operating lease variable cost	1,829		1,782
Total operating lease costs	$	2,329	$	2,360

At December 31, 2022, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2022
2023	$	307
2024	150
2025	146
2026	143
2027	142
Thereafter	2,196
Total lease payments	3,084
Less imputed interest	(1,610)
Total	$	1,474

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Recently Adopted Accounting Standards

Debt

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Reference Rate Reform

On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2022		2021
Pension benefits (1)	$	120	$	708	Indefinitely
Environmental compliance costs	1,193		1,089		32 years
Utility retained generation (2)	86		133		4 years
Price risk management	177		216		17 years
Catastrophic event memorandum account (3)	1,085		1,119		1 - 3 years
Wildfire expense memorandum account (4)	439		347		TBD years
Fire hazard prevention memorandum account (5)	79		75		1 - 3 years
Fire risk mitigation memorandum account (6)	65		44		1 - 3 years
Wildfire mitigation plan memorandum account (7)	756		424		1 - 3 years
Deferred income taxes (8)	2,730		1,849		51 years
Insurance premium costs (9)	99		207		2 - 4 years
Wildfire mitigation balancing account (10)	327		273		1 - 3 years
Vegetation management balancing account (11)	2,276		1,411		1 - 3 years
COVID-19 pandemic protection memorandum accounts (12)	26		49		TBD years
Microgrid memorandum account (13)	213		163		1 - 3 years
Financing costs (14)	211		175		Various
SB 901 securitization (15)	5,378		—		30 years
AROs in excess of recoveries (16)	120		—		Various
Other	1,063		925		Various
Total long-term regulatory assets	$	16,443	$	9,207

(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.

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(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 2001 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) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2022 and 2021, $44 million and $49 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.

(6) Includes costs primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. Recovery of WMPMA costs is subject to CPUC review and approval.

(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.

(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2022. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.

(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.

(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date.

(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below.

(16) 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 asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  See Note 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2022 and 2021, the Utility had current regulatory liabilities of $1.12 billion and $698 million, respectively. At December 31, 2022, current regulatory liabilities consisted primarily of unrealized gains associated with the change in fair value of price risk management instruments that meet the definition of a derivative. An increase in natural gas prices has affected both the Utility’s gas and electric price risk management instruments, resulting in a deferral of $604 million. For more information, see Note 11 below. Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets.

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Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2022		2021
Cost of removal obligations (1)	$	7,773	$	7,306
Recoveries in excess of AROs (2)	—		388
Public purpose programs (3)	1,062		946
Employee benefit plans (4)	904		1,229
Transmission tower wireless licenses (5)	430		446
SFGO sale (6)	264		343
SB 901 securitization (7)	5,800		—
Other	1,397		1,341
Total long-term regulatory liabilities	$	17,630	$	11,999

(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.

(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 held 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 12 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.

(4) Represents cumulative differences between incurred costs and amounts collected in rates for post-retirement medical, post-retirement life and long-term disability plans.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.

(7) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement. See Note 6 below.

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 fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.

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

	Receivable Balance at December 31,
(in millions)	2022		2021
Electric distribution (1)	$	448	$	—
Gas distribution and transmission (2)	72		—
Energy procurement (3)	684		310
Public purpose programs (4)	358		321
Fire hazard prevention memorandum account (5)	—		50
Fire risk mitigation memorandum account (6)	—		14
Wildfire mitigation plan memorandum account (7)	—		67
Wildfire mitigation balancing account (8)	2		91
General rate case memorandum accounts (9)	3		468
Vegetation management balancing account (10)	137		127
Insurance premium costs (11)	602		605
Wildfire expense memorandum account (12)	—		440
Residential uncollectibles balancing accounts (13)	126		127
Catastrophic event memorandum account	144		—
Other	688		379
Total regulatory balancing accounts receivable	$	3,264	$	2,999

	Payable Balance at December 31,
(in millions)	2022		2021
Electric distribution (1)	$	—	$	121
Electric transmission (14)	228		24
Gas distribution and transmission (2)	66		83
Energy procurement (3)	428		211
Public purpose programs (4)	272		259
Nuclear decommissioning adjustment mechanism (15)	8		137
SFGO sale	152		21
Other	504		265
Total regulatory balancing accounts payable	$	1,658	$	1,121

(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(2) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings. 

(3) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. 

(4) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery.

(9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC.

(10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery.

(11) The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets.

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(12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022.

(13) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers.

(14) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.

(15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant.

NOTE 5: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2022:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2027	$	4,400	(1)	$	(1,930)	$	(998)	$	1,472
Utility receivables securitization program (2)	September 2024	1,389		(3)	(1,184)		—		205		(3)
PG&E Corporation revolving credit facility	June 2025	500			—		—		500
Total credit facilities		$	6,289		$	(3,114)	$	(998)	$	2,177

(1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

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On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

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On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”).

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order.

For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above.

Long-Term Debt Issuances and Redemptions

Utility

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2022		December 31, 2021
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,681	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of unamortized discount and debt issuance costs		(28)		(26)
Unamortized discount/premium and debt issuance costs, net		(66)		(90)
Total PG&E Corporation Long-Term Debt		4,587		4,593
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	—		500
2022	1.75%	—		2,500
2023	1.70% - 4.25%	2,075		3,575
2024	3.25% - 3.75%	1,800		800
2025	3.45% - 4.95%	1,925		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		2,550
2028	3.00% - 4.65%	1,975		1,975
2029	4.20%	400		—
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		—
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		700
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
2052	5.25%	550		—
Less: current portion, net of unamortized discount and debt issuance costs		(2,072)		(2,996)
Unamortized discount, premium and debt issuance costs, net		(195)		(190)
Total Utility First Mortgage Bonds		32,135		31,816
Recovery Bonds (3)		9,292		860
Less: current portion		(168)		(18)
DWR Loan (4)		312		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2024	variable rate (5)	1,184		974
2-Year Term Loan - Stated Maturity: 2024	variable rate (6)	400		—
18-month Term Loan - Stated Maturity: 2023	variable rate (7)	—		1,441
Less: current portion		—		(1,441)
Total Utility Long-Term Debt		43,155		33,632
Total PG&E Corporation Consolidated Long-Term Debt		$	47,742	$	38,225

(1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively.

(2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates.

(4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance.

(5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%.

(6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%.

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(7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below:

(in millions, except interest rates)	2023			2024			2025			2026			2027			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2022	7.13		%	7.13		%	7.13		%	—		%	—		%	—		%	7.13		%
Variable rate obligations	$	28		$	28		$	2,625		$	—		$	—		$	—		$	2,681
Utility (1)
Average fixed interest rate	2.91		%	3.40		%	3.82		%	3.10		%	3.22		%	4.12		%	3.84		%
Fixed rate obligations	$	2,075		$	1,800		$	1,925		$	2,551		$	3,000		$	23,051		$	34,402
Variable interest rate as of December 31, 2022	—		%	5.54		%	—		%	—		%	—		%	—		%	5.54		%
Variable rate obligations	$	—		$	1,584		$	—		$	—		$	—		$	—		$	1,584
Recovery Bonds (2)
AB 1054 obligations	$	38		$	46		$	48		$	50		$	51		$	1,592		$	1,825
SB 901 obligations	$	130		$	129		$	135		$	141		$	146		$	6,786		$	7,467
Total consolidated debt	$	2,271		$	3,587		$	4,733		$	2,742		$	3,197		$	33,429		$	49,959

(1) The balance excludes DWR loan, see Note 3 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6.

NOTE 6: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

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On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable.

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date.

On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date.

Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 12). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

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Also pursuant to the CHT decision, upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (See Note 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes.

The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities:

SB 901 securitization regulatory asset (in millions)
Regulatory asset balance at inception	$	5,500
Amortization	(122)
Balance at December 31, 2022	$	5,378

SB 901 securitization regulatory liability (in millions)
Regulatory liability balance at inception	$	(5,540)
Amortization	308
Additions	(568)
Balance at December 31, 2022	$	(5,800)

NOTE 7: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,987,784,948 shares of common stock outstanding at December 31, 2022, which excludes 247,743,590 shares of common stock owned by ShareCo, and 230,000,000 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2022.

Equity Offerings

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts.

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At the Market Equity Distribution Program

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.

The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.

On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of the outstanding shares. At various dates throughout 2022, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

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Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

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.  Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.  

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

Long-Term Incentive Plans

The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, 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 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 53,350,101 shares were available for future awards at December 31, 2022.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2022:

(in millions)	2022		2021		2020
Stock Options	$	—	$	—	$	3
Restricted stock units	60		35		15
Performance shares	55		21		17
Total compensation expense (pre-tax)	$	115	$	56	$	35
Total compensation expense (after-tax)	$	83	$	40	$	25

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

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Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2022, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2022 or 2021.  

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2022.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,195,834	$	7.42		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(43,702)	10.23			—
Outstanding at December 31	2,152,132	7.36		2.41	—
Vested or expected to vest at December 31	2,152,132	7.36		2.41	—
Exercisable at December 31	2,152,132	$	7.36	2.41	$	—

(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units 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 ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2022, 2021, and 2020 was $11.40, $11.01, and $9.25, respectively.  The total fair value of restricted stock units that vested during 2022, 2021, and 2020 was $46 million, $19 million, and $31 million, respectively.  The tax detriment from restricted stock units that vested in 2022 was $4 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2022, $74 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48 years.

The following table summarizes restricted stock unit activity for 2022:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	10,090,375	$	11.00
Granted	5,850,945	11.40
Vested	(4,175,008)	10.96
Forfeited	(788,192)	11.18
Nonvested at December 31	10,978,120	$	11.21

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Performance Shares

Performance shares generally vest three years after the grant date.  Following 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 (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-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 during 2022, 2021, and 2020 was $13.44, $11.83, and $9.62 respectively.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2022, $43 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 0.94 years.

The following table summarizes activity for performance shares in 2022:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	8,567,009	$	9.64
Granted	3,105,604	13.44
Vested	—	—
Forfeited	(650,559)	10.15
Nonvested at December 31	11,022,054	$	10.68

NOTE 8: PREFERRED STOCK

PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2022 and 2021, 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, respectively.  The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

On December 31, 2022, 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, 2022, 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.  On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the dividends paid in arrears, the Utility paid approximately $11 million of dividends on redeemable preferred stock during the year ended December 31, 2022. On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023.

The Utility paid no dividends on preferred stock in 2021 or 2020.

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NOTE 9: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2022, 2021, and 2020.

	Year Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Income (loss) available for common shareholders	$	1,800	$	(102)	$	(1,318)
Weighted average common shares outstanding, basic	1,987		1,985		1,257
Add incremental shares from assumed conversions:
Employee share-based compensation	8		—		—
Equity Units	137		—		—
Weighted average common shares outstanding, diluted	2,132		1,985		1,257
Total earnings (loss) per common share, diluted	$	0.84	$	(0.05)	$	(1.05)

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 10: 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 DTAs and liabilities.  DTAs 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 technical merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. 

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

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. 

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

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2022		2021		2020		2022		2021		2020
Current:
Federal	$	(1)	$	—	$	(26)	$	(1)	$	—	$	(26)
State	—		1		(34)		—		—		(34)
Deferred:
Federal	(943)		543		258		(852)		588		290
State	(389)		296		171		(348)		316		185
Tax credits	(5)		(4)		(7)		(5)		(4)		(7)
Income tax provision (benefit)	$	(1,338)	$	836	$	362	$	(1,206)	$	900	$	408

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2022		2021		2022		2021
Deferred income tax assets:
Tax carryforwards	$	7,156	$	5,628	$	6,868	$	5,425
Compensation	157		185		80		108
Greenhouse gas allowance	239		157		239		157
Wildfire-related claims (1)	1,489		1,723		1,489		1,723
Operating lease liability	368		346		368		346
Transmission tower wireless licenses	254		266		254		266
Other (2)	197		121		177		136
Total deferred income tax assets	$	9,860	$	8,426	$	9,475	$	8,161
Deferred income tax liabilities:
Property related basis differences	9,374		8,847		9,363		8,835
Regulatory balancing accounts	1,376		1,193		1,376		1,193
Debt financing costs	465		501		465		501
Operating lease right of use asset	368		346		368		346
Income tax regulatory asset (3)	764		517		764		517
Other (4)	245		199		230		178
Total deferred income tax liabilities	$	12,592	$	11,603	$	12,566	$	11,570
Total net deferred income tax liabilities	$	2,732	$	3,177	$	3,091	$	3,409

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service area over the past several years.

(2) Amounts include benefits, state taxes, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

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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,
	2022		2021		2020		2022		2021		2020
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(75.8)		31.3		(15.3)		(26.9)		24.1		19.1
Effect of regulatory treatment of fixed asset differences (2)	(123.8)		(71.5)		39.0		(49.2)		(51.6)		(44.9)
Tax credits	(3.2)		(1.7)		1.5		(1.3)		(1.2)		(1.7)
Fire Victim Trust (3)	(160.9)		127.3		(44.9)		(64.0)		91.9		51.7
Bankruptcy and emergence	—		—		(37.6)		—		—		2.4
Other, net (4)	12.9		5.3		(2.1)		2.2		2.6		2.2
Effective tax rate	(329.8)	%	111.7	%	(38.4)	%	(118.2)	%	86.8	%	49.8	%

(1) Includes the effect of state flow-through ratemaking treatment.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  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.  In 2022, 2021, and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) The Utility includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2022		2021		2020		2022		2021		2020
Balance at beginning of year	$	498	$	437	$	420	$	498	$	437	$	420
Reductions for tax position taken during a prior year	(1)		(23)		(43)		(1)		(23)		(43)
Additions for tax position taken during the current year	73		85		60		73		85		60
Settlements	—		(1)		—		—		(1)		—
Balance at end of year	$	570	$	498	$	437	$	570	$	498	$	437

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2022 for PG&E Corporation and the Utility was $31 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress.

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, 2022, 2021, and 2020, these amounts were immaterial.

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Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. The Internal Revenue Service is auditing tax years 2015 through 2018.

PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California. The State of California is auditing tax years 2015 through 2019.

Carryforwards

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

(in millions)	December 31, 2022		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,447	2031 - 2036
Net operating loss carryforward - Post-2017	23,170		N/A
Tax credit carryforward	152		2029 - 2041
State:
Net operating loss carryforward	$	25,169	2039 - 2041
Tax credit carryforward	126		Various

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.

Other Tax Matters

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. Half of the payment was paid in 2021, and the other half of the payment was paid in 2022.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). Due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

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Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. From inception through December 31, 2022, the Fire Victim Trust exchanged Plan Shares in the aggregate amount of 230,000,000 for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. In the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. On January 9, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares and thereafter the Fire Victim Trust reported that it sold the applicable New Shares. An aggregate tax benefit of $256 million will be recorded in January 2023. For more information, see Note 7 above.

NOTE 11: 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 rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and 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 through 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. 

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume at
Underlying Product	Instruments	December 31, 2022	December 31, 2021
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	171,212,813	173,361,635
	Options	27,785,000	14,420,000
Electricity (MWh)	Forwards, Futures and Swaps	10,814,728	10,283,639
	Options	215,600	288,000
	Congestion Revenue Rights (3)	205,743,505	239,857,610

(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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Presentation of Derivative Instruments in the Financial Statements

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

As of December 31, 2021, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.

Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2022, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 12: 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:

•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	658	$	—	$	—	$	—	$	658
Fixed-income securities	—		49		—		—		49
Nuclear decommissioning trusts
Short-term investments	117		—		—		—		117
Global equity securities	1,845		—		—		—		1,845
Fixed-income securities	1,094		791		—		—		1,885
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,056		791		—		—		3,872
Customer credit trust
Short-term investments	19		—		—		—		19
Global equity securities	218		—		—		—		218
Fixed-income securities	216		292		—		—		508
Total customer credit trust	453		292		—		—		745
Price risk management instruments (Note 11)
Electricity	—		94		432		40		566
Gas	—		604		—		327		931
Total price risk management instruments	—		698		432		367		1,497
Rabbi trusts
Short-term investments	25		—		—		—		25
Global equity securities	5		—		—		—		5
Fixed-income securities	—		69		—		—		69
Life insurance contracts	—		64		—		—		64
Total rabbi trusts	30		133		—		—		163
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	10		—		—		—		143
TOTAL ASSETS	$	4,207	$	1,963	$	432	$	367	$	7,127
Liabilities:
Price risk management instruments (Note 11)
Electricity	$	—	$	10	$	233	$	(20)	$	223
Gas	—		172		—		(166)		6
TOTAL LIABILITIES	$	—	$	182	$	233	$	(186)	$	229

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

(2) Represents amount before deducting $575 million primarily related to deferred taxes on appreciation of investment value. 

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	Fair Value Measurements
	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 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. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2022 and 2021.

Trust Assets

Assets Measured at Fair Value

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, customer credit 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 classified as 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 fixed-income 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 Using Practical Expedient

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, credit securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, 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 futures 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 futures, 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.  The Utility 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 Uncertainty Analysis

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 rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments.  See Note 11 above.

	Fair Value at
(in millions)	At December 31, 2022				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	305	$	138	Market approach	CRR auction prices	$ (145.09) - 2,724.93 / 0.89
Power purchase agreements	$	127	$	95	Discounted cash flow	Forward prices	$ (6.39) - 286.75 / 78.14

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

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	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2022 and 2021, respectively:

	Price Risk Management Instruments
(in millions)	2022		2021
Liability balance as of January 1	$	(34)	$	(72)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	233		38
Asset (Liability) balance as of December 31	$	199	$	(34)

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

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, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of December 31, 2022 and December 31, 2021, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At December 31, 2022				At December 31, 2021
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,355	$	4,490	$	4,619	$	4,796
Utility	32,847		27,666		31,816		35,803

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Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Nuclear decommissioning trusts
Short-term investments	$	117	$	—	$	—	$	117
Global equity securities	413		1,468		(11)		1,870
Fixed-income securities	1,991		10		(116)		1,885
Total (1)	$	2,521	$	1,478	$	(127)	$	3,872
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581

(1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, 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, 2022
Less than 1 year	$	42
1–5 years	624
5–10 years	400
More than 10 years	819
Total maturities of fixed-income securities	$	1,885

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

(in millions)	2022		2021		2020
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	3,316	$	1,678	$	1,518
Gross realized gains on securities	2		286		159
Gross realized losses on securities	(3)		(19)		(41)

Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Customer credit trust
Short-term investments	$	19	$	—	$	—	$	19
Global equity securities	219		13		(14)		218
Fixed-income securities	516		—		(8)		508
Total	$	754	$	13	$	(22)	$	745

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

	As of
(in millions)	December 31, 2022
Less than 1 year	$	79
1–5 years	123
5–10 years	120
More than 10 years	186
Total maturities of fixed-income securities	$	508

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

(in millions)	2022
Proceeds from sales and maturities of customer credit trust investments	$	250
Gross realized gains on securities	10
Gross realized losses on securities (1)	(41)

(1) Includes $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2022.

NOTE 13: 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”).  Certain trusts underlying these plans are qualified trusts under the IRC.  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.  On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates.

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 2022 and 2021:

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Pension Plan

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	21,895	$	20,759
Actual return on plan assets	(4,916)		1,693
Company contributions	339		335
Benefits and expenses paid	(949)		(892)
Fair value of plan assets at end of year	$	16,369	$	21,895
Change in benefit obligation:
Benefit obligation at beginning of year	$	22,759	$	23,172
Service cost for benefits earned	575		587
Interest cost	692		645
Actuarial gain (1)	(6,471)		(752)
Plan amendments	—		—
Benefits and expenses paid	(947)		(893)
Benefit obligation at end of year (2)	$	16,608	$	22,759
Funded Status:
Current liability	$	(8)	$	(9)
Noncurrent liability	(231)		(856)
Net liability at end of year	$	(239)	$	(865)

(1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively.

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Postretirement Benefits Other than Pensions

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	3,102	$	2,995
Actual return on plan assets	(693)		193
Company contributions	26		10
Plan participant contribution	81		80
Benefits and expenses paid	(180)		(176)
Fair value of plan assets at end of year	$	2,336	$	3,102
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766	$	1,876
Service cost for benefits earned	62		63
Interest cost	53		51
Actuarial gain (1)	(486)		(152)
Benefits and expenses paid	(162)		(156)
Federal subsidy on benefits paid	3		4
Plan participant contributions	81		80
VSP related termination benefits (3)	22		—
Benefit obligation at end of year	$	1,339	$	1,766
Funded Status: (2)
Noncurrent asset	$	997	$	1,340
Noncurrent liability	—		(4)
Net asset at end of year	$	997	$	1,336

(1) The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes

(2) At December 31, 2022 and 2021, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively.

(3) Represents VSP-related credits to employee retirement health savings accounts. See Note 3 above.

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

Components of Net Periodic Benefit Cost

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.

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Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	575	$	587	$	530
Interest cost	692		645		713
Expected return on plan assets	(1,189)		(1,046)		(1,044)
Amortization of prior service cost	(4)		(6)		(6)
Amortization of net actuarial loss	2		6		3
Net periodic benefit cost	76		186		196
Less: transfer to regulatory account (2)	254		147		136
Total expense recognized	$	330	$	333	$	332

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	62	$	63	$	61
Interest cost	53		51		63
Expected return on plan assets	(130)		(137)		(138)
Amortization of prior service cost	7		14		14
Amortization of net actuarial loss	(40)		(33)		(21)
Special termination benefits	22		—		—
Net periodic benefit cost	$	(26)	$	(42)	$	(21)

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.

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).

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Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2022		2021		2020		2022	2021	2020
Discount rate	5.54	%	3.03	%	2.77	%	5.50 - 5.54%	2.97 - 3.04%	2.67 - 2.80%
Rate of future compensation increases	3.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.10	%	5.50	%	5.10	%	3.70 - 7.30%	3.30 - 6.40%	3.10 - 6.10%
Interest crediting rate for cash balance plan	4.19	%	1.95	%	1.95	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2022 was 6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 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 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 projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.1% compares to a ten-year actual return of 5.8%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 848 Aa-grade non-callable bonds at December 31, 2022.  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 global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios. 

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 allocation between fixed income and equity 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.

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

	Pension Plan						PBOP Plans
	2023		2022		2021		2023		2022		2021
Global equity securities	26	%	30	%	30	%	28	%	26	%	36	%
Absolute return	1	%	2	%	2	%	1	%	1	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	5	%
Fixed-income securities	65	%	60	%	60	%	68	%	70	%	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, 2022 and 2021.

	Fair Value Measurements
	At December 31,
	2022								2021
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	461	$	126	$	—	$	587	$	552	$	255	$	—	$	807
Global equity securities	1,430		—		—		1,430		2,074		424		—		2,498
Absolute Return	—		—		—		—		—		1		—		1
Real assets	426		—		—		426		632		—		—		632
Fixed-income securities	1,946		6,086		8		8,040		2,729		7,388		27		10,144
Assets measured at NAV	—		—		—		5,886		—		—		—		7,972
Total	$	4,263	$	6,212	$	8	$	16,369	$	5,987	$	8,068	$	27	$	22,054
PBOP Plans:
Short-term investments	$	26	$	—	$	—	$	26	$	31	$	—	$	—	$	31
Global equity securities	83		—		—		83		105		—		—		105
Real assets	29		—		—		29		34		—		—		34
Fixed-income securities	406		702		1		1,109		776		875		1		1,652
Assets measured at NAV	—		—		—		1,100		—		—		—		1,296
Total	$	544	$	702	$	1	$	2,347	$	946	$	875	$	1	$	3,118
Total plan assets at fair value							$	18,716							$	25,172

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $11 million and $175 million at December 31, 2022 and 2021, 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 NAV per share can be redeemed quarterly with a notice not to exceed 90 days.

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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 Securities

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 Securities

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.

Assets Measured at NAV Using Practical Expedient

Investments in the trusts 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, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2022 or 2021.

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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, 2022 and 2021:

(in millions)
For the year ended December 31, 2022	Fixed-Income
Balance at beginning of year	$	27
Actual return on plan assets:
Relating to assets still held at the reporting date	1
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	(26)
Balance at end of year	$	8
(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27

There were no material transfers out of Level 3 in 2022 or 2021.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $339 million to the pension benefit plans and $26 million to the other benefit plans in 2022.  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 2022.  The Utility’s pension benefits met all the funding requirements under the Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2023. PG&E Corporation and the Utility did not request to make contributions to the other postretirement benefit plans in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2022, 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:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2023	907	97	(4)
2024	996	98	(4)
2025	1028	100	(4)
2026	1057	94	(4)
2027	1,082	94	(4)
Thereafter in the succeeding five years	5,702	475	(4)

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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 IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provides 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 $144 million, $133 million, and $119 million in 2022, 2021, and 2020, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

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

NOTE 14: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2022		2021		2020
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	104	$	82	$	108
Utility employee benefit due to PG&E Corporation	85		39		34

At December 31, 2022 and 2021, the Utility had receivables of $33 million and $173 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $46 million and $19 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

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NOTE 15: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

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Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation.

On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed.

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As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022.

On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire.

Additionally, on July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	769
Accrued Losses	225
Payments	(344)
Balance at December 31, 2022	$	650

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

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On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

Various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for August 14, 2023.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

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Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	211
Accrued Losses	25
Payments	(204)
Balance at December 31, 2022	$	32

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2022, the Utility recorded an insurance receivable for $370 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $30 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

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On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation.

On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire.

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Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	1,150
Accrued Losses	25
Payments	(44)
Balance at December 31, 2022	$	1,131

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of December 31, 2022, the Utility recorded an insurance receivable of $530 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $370 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2022, the Utility recorded a Wildfire Fund receivable of $175 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $115 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $388 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. The WEMA regulatory asset increased by $41 million during the year ended December 31, 2022.

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2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 13 structures damaged, and 78 structures destroyed and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 236 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further such complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency and a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million during the quarter ended September 30, 2022 (before available recoveries). The aggregate liability remained unchanged as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. The Utility’s accrued estimated losses also do not include any assumptions regarding offsetting recoveries from third-parties (outside of the Utility’s insurers).

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $940 million, with a deductible of $60 million. As of December 31, 2022, the Utility recorded an insurance receivable of $45 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of December 31, 2022, the Utility also recorded a $10 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $50 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

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Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2022 are:

Potential Recovery Source (in millions)	2022 Mosquito fire		2021 Dixie fire
Insurance	$	45	$	530
FERC TO rates	10		115
WEMA	50		388
Wildfire Fund	—		175
Probable recoveries at December 31, 2022	$	105	$	1,208

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In April 2022, the Utility purchased approximately $725 million in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of December 31, 2022, PG&E Corporation and the Utility had prepaid insurance of $424 million, reflected in Other current assets on the Consolidated Balance Sheets.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2022, PG&E Corporation and the Utility recorded $430 million, $370 million, $530 million, and $45 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

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The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2021	$	—	$	563	$	270	$	414	$	1,247
Accrued insurance recoveries (1)	45		(33)		33		—		45
Reimbursements	—		—		(185)		(313)		(498)
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794

(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

During the year ended December 31, 2022, PG&E Corporation and the Utility resolved property related claims in the amount of $418 million, net of self-insured retention, of which approximately $13 million is reflected in Accounts receivable, other on the Consolidated Financial Statements (excluded from the table above).

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2022, the Utility recorded reductions of $115 million and $10 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of December 31, 2022, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $388 million and $50 million, respectively, as regulatory assets in the WEMA. Cost recovery for incremental insurance premiums is addressed through balancing account mechanisms.

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Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of December 31, 2022 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.0 billion based on its 2022 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

As of December 31, 2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview

As further described under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. These securities claims are collectively referred to in this section as the “Wildfire-Related Securities Claims.”

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Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the terms of the FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with certain carriers of the D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the Wildfire-Related Securities Claims. As of December 31, 2022 and each as further described below:

•For the Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the consolidated securities action, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.

•For the Insurance Coverage Claims, PG&E Corporation entered into agreements with certain of its D&O Insurance carriers to settle the majority of the Insurance Coverage Claims and has received the full settlement amount of $272 million.

•For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O insurance policy proceeds. PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

As a result, PG&E Corporation believes it is probable that it will incur a net loss of $145 million in connection with these matters. As of December 31, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Consolidated Statements of Income.

In the event that one or more of the settlements in these matters does not become effective, some or all parties are expected to continue to litigate, and at least some of the amounts of PG&E Corporation’s expected liabilities will remain uncertain.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain then-current and former members of the boards of directors and certain then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). On April 13, 2018, the plaintiffs filed a consolidated complaint. On January 28, 2019, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims, if any, directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation or the Utility for amounts owed pursuant to their indemnification obligations in connection with such causes of action. On March 8, 2021, the court granted a stipulation by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.

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On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O Insurance policy proceeds, and in return, the Fire Victim Trust released, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement was paid solely from the insurance proceeds from the “Side B” D&O Insurance coverage. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action was dismissed with prejudice on December 29, 2022.

On January 25, 2019, a separate purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The plaintiff filed a request to dismiss this action, and on October 12, 2022, the court dismissed the action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA’s opening brief for the appeal is due March 6, 2023, and the answering brief is due April 5, 2023.

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Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. In the second quarter of 2022, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such agreement.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

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On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. PERA’s appeal to the Ninth Circuit Court of Appeals remains pending.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with certain carriers regarding, among other things, the applicability of one year of D&O Insurance policies to those matters (the “Insurance Coverage Claims”).

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled the majority of the Insurance Coverage Claims with certain of their D&O Insurance carriers. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.

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On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to May 19, 2023.

NOTE 16: OTHER 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, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation and the Utility 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’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

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 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. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $258 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in the TO18 proceeding.

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On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

2022 Cost of Capital Application

The Utility’s annual cost of capital adjustment mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure.

In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes beginning on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application. As of December 31, 2022, the Utility had not recorded a reserve for refunds related to these memorandum accounts.

On November 3, 2022, the CPUC issued a final decision finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. The final decision retains the cost of capital previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility filed a response to the application for rehearing.

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Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters totaled $69 million and $77 million as of December 31, 2022 and December 31, 2021, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022.

The Utility is unable to determine the timing and outcome of this proceeding.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded charges during the fourth quarters of 2021 and 2022, each for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

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Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities 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. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. 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 comprised of the following:

	Balance at
(in millions)	December 31, 2022		December 31, 2021
Topock natural gas compressor station	$	284	$	299
Hinkley natural gas compressor station	110		123
Former MGP sites owned by the Utility or third parties (1)	750		667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		104
Fossil fuel-fired generation facilities and sites (3)	26		70
Total environmental remediation liability	$	1,282	$	1,263

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.

(2) Primarily driven by geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP 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 Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program 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 the environmental requirements on an ongoing basis 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 as of December 31, 2022, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  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. As of December 31, 2022, the Utility expected to recover $1.05 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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.

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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 U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $240 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater 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 California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility 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 sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2023. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $126 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $511 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $51 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

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NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more terrorist acts occurring within a 12-month period at member sites. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more cyber events occurring within a 12-month period at member sites. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, 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. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. The coverage procured through EMANI also includes protection for acts of terrorism.

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, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

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 approximately $13.7 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.7 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

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 $450 million per incident. In addition, the Utility has approximately $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 for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

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, 2022:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2023	$	2,081	$	482	$	60	$	1,746	$	47	$	4,416
2024	2,052		378		61		195		11		2,697
2025	2,040		715		61		140		—		2,956
2026	1,980		663		21		129		—		2,793
2027	1,919		579		7		53		—		2,558
Thereafter	17,807		1,565		13		—		—		19,385
Total purchase commitments	$	27,879	$	4,382	$	223	$	2,263	$	58	$	34,805

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Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  These renewable energy contracts expire at various dates between 2023 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 RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2023 and 2041.

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. As of December 31, 2022, QF contracts in operation expire at various dates between 2023 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.8 billion in 2022, $3.0 billion in 2021, and $2.9 billion in 2020.

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 United States 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 2023 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California 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, were $2.4 billion in 2022, $1.2 billion in 2021, and $0.8 billion in 2020.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2023 and 2024 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 were $44 million in 2022, $79 million in 2021, and $111 million in 2020.

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Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2023 and 2057.  At December 31, 2022, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2023	$	88
2024	85
2025	83
2026	81
2027	80
Thereafter	3,518
Total minimum lease payments	$	3,935

Payments for other commitments were $63 million in 2022, $50 million in 2021, and $45 million in 2020.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

In addition to the commitments in the table above, pursuant to SB 901, a shareholder contribution to the customer credit trust of $1.0 billion is to be made in 2024.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL 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, 2022, 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, 2022.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2022, 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 shareholders and the Board of Directors of PG&E Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes and the schedules listed in the Index at Item 15 (collectively, referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 22, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulation and Regulated Operations—Refer to Notes 3, 4 and 15 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company (the “Utility”), follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“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 and records regulatory liabilities for amounts that are likely to be refunded to customers. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the significant degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators, as well as likelihood of refunds to customers. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a significant degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or likely refund as a regulatory liability under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators and costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC and FERC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Company met the definition of a refund or a future reduction in rates.

•We evaluated whether the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 15 to the financial statements

Critical Audit Matter Description

The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire, 2021 Dixie fire, and 2022 Mosquito fire. The Company has recorded estimated probable losses of $1,025 million, $400 million, $1,175 million, and $100 million, respectively, as of December 31, 2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Company has recorded estimated recoveries of wildfire-related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

We identified wildfire-related contingencies and related-recoveries, specifically the WEMA and Wildfire Fund, as well as the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses, (2) the outcome of the wildfire-related contingencies materially affects the Company’s financial position, results of operations, and cash flows and (3) the significant judgments made by management in determining whether recoveries from WEMA and the Wildfire Fund are probable. This required the application of a significant degree of auditor judgment and audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses, related recoveries, and disclosures.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies, related recoveries, and disclosures included the following, among others:

•We tested the effectiveness of controls over (1) the Company’s determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Company’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of each fire, information from claimants, communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Company’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America.

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Company’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

SB 901 Securitization—Refer to Note 6 to the financial statements

Critical Audit Matter Description

SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish a customer credit trust funded by the Company’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Company’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust. The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

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Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax benefits the Utility has recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

We identified the accounting for the SB 901 securitization as a critical audit matter due to the significant judgments made by management in the application of the relevant GAAP. This required specialized knowledge of accounting for rate regulation required significant audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the SB 901 securitization included the following:

•We tested the effectiveness of controls over the evaluation of the accounting treatment for the SB 901 securitization and disclosures related to the securitization.

•With the assistance of professionals in our firm having expertise in accounting for rate regulation, we evaluated the conclusions regarding the regulatory asset, regulatory liability, expense and tax accounting treatment applied to the SB 901 securitization by performing the following:

◦Read the terms and conditions included in the financing order, as well as correspondence with the CPUC regarding the intent of the securitization.

◦Evaluated the conclusions regarding the GAAP applied to account for the transaction.

•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire Fund—Refer to Notes 3 and 14 to the financial statements

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. The Company accounts for the contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines. As of December 31, 2022, the Wildfire Fund asset is $5.3 billion and the related amortization and accretion for the year ended December 31, 2022 is $477 million. AB 1054 did not specify a period of coverage; therefore the Company estimated the useful life of 15 years using a Monte Carlo simulation.

We identified the Company’s accounting for the Wildfire Fund asset as a critical audit matter due to significant judgments made by management to determine the useful life, specifically the updated assumption related to the effectiveness of wildfire mitigation efforts. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve actuarial specialists when performing audit procedures to evaluate the Company’s accounting and disclosure related to the Wildfire Fund.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Wildfire Fund included the following:

•We tested the effectiveness of controls over (1) the Company’s review of the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts, (2) review of the Monte Carlo simulation methodology used to develop useful life estimate and (3) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

•With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.

•We evaluated each of management’s key assumptions to the useful life estimate and judgments made by management, including those related to the effectiveness of wildfire mitigation efforts, by inquiring of management, comparing the assumptions to relevant source data, performing sensitivity analyses including information filed with the Company’s regulator related to wildfire mitigation efforts and other publicly available data. Additionally, we inspected relevant source data for any evidence that might contradict management’s assertions.

•We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

We have served as the Company’s auditor since 1999.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes and the schedules listed in the Index at Item 15 (collectively, referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Utility’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2023, expressed an unqualified opinion on the Utility’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Utility’s management. Our responsibility is to express an opinion on the Utility’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulation and Regulated Operations—Refer to Notes 3, 4, and 15 to the financial statements

Critical Audit Matter Description

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“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 and records regulatory liabilities for amounts that are likely to be refunded to customers. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the significant degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators, as well as likelihood of refunds to customers. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a significant degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or likely refund as a regulatory liability under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators and costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC and FERC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Utility met the definition of a refund or a future reduction in rates.

•We evaluated whether the Utility’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 15 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire, 2021 Dixie fire and 2022 Mosquito fire. The Utility has recorded estimated probable losses of $1,025 million,$400 million, $1,175 million, and $100 million, respectively as of December 31, 2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Utility has recorded estimated recoveries of wildfire‐related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

We identified wildfire-related contingencies and related-recoveries, specifically the WEMA and Wildfire Fund, as well as the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses, (2) the outcome of the wildfire-related contingencies materially affects the Utility’s financial position, results of operations, and cash flows and (3) the significant judgments made by management in determining whether recoveries from WEMA and the Wildfire Fund are probable. This required the application of a significant degree of auditor judgment and audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses, related recoveries, and disclosures.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies, related recoveries, and disclosures included the following, among others:

•We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Utility’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of each fire, information from claimants, communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Utility’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America..

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Utility’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

•We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

SB 901 Securitization—Refer to Note 6 to the financial statements

Critical Audit Matter Description

SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish a customer credit trust funded by the Utility’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Utility’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust. The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

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Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax benefits the Utility has recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

We identified the accounting for the SB 901 securitization as a critical audit matter due to the significant judgments made by management in the application of the relevant GAAP. This required specialized knowledge of accounting for rate regulation required significant audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the SB 901 securitization included the following:

•We tested the effectiveness of controls over the evaluation of the accounting treatment for the SB 901 securitization and disclosures related to the securitization.

•With the assistance of professionals in our firm having expertise in accounting for rate regulation, we evaluated the conclusions regarding the regulatory asset, regulatory liability, expense and tax accounting treatment applied to the SB 901 securitization by performing the following:

◦Read the terms and conditions included in the financing order, as well as correspondence with the CPUC regarding the intent of the securitization.

◦Evaluated the conclusions regarding the GAAP applied to account for the transaction.

•We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire Fund—Refer to Notes 3 and 14 to the financial statements

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019, that are caused by the applicable electric utility company’s equipment. The Utility accounts for the contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines. As of December 31, 2022, the Wildfire Fund asset is $5.3 billion and the related amortization and accretion for the year ended December 31, 2022 is $477 million. AB 1054 did not specify a period of coverage; therefore, the Utility estimated the useful life of 15 years using a Monte Carlo simulation.

We identified the Utility’s accounting for the Wildfire Fund asset as a critical audit matter due to significant judgments made by management to determine the useful life, specifically the updated assumption related to the effectiveness of wildfire mitigation efforts. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve actuarial specialists when performing audit procedures to evaluate the Utility’s accounting and disclosure related to the Wildfire Fund.

190

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Wildfire Fund included the following:

•We tested the effectiveness of controls over (1) the Utility’s review of the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts, (2) review of the Monte Carlo simulation methodology used to develop useful life estimate and (3) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

•With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.

•We evaluated each of management’s key assumptions to the useful life estimate and judgments made by management, including those related to the effectiveness of wildfire mitigation efforts, by inquiring of management, comparing the assumptions to relevant source data, performing sensitivity analyses including information filed with the Utility’s regulator related to wildfire mitigation efforts and other publicly available data. Additionally, we inspected relevant source data for any evidence that might contradict management’s assertions.

•We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

We have served as the Utility’s auditor since 1999.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of PG&E Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 22, 2023, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’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 internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’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. 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 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.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

192

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Utility and our report dated February 22, 2023, expressed an unqualified opinion on those financial statements.

Basis for Opinion

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 Utility’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’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. 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 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.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCE DISCLOSURE

Not applicable.

ITEM 9A. 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 December 31, 2022, 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 2022 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 December 31, 2022, 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 December 31, 2022 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.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

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PART III 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Information About Our Executive Officers” at the end of Part I of this 2022 Form 10-K. Other information required by this Item 10 will be included in the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders under the headings “Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” (under the subheadings “Nominees,” “Committee Responsibilities,” “Committee Membership Requirements,” and “Section 16(a) Beneficial Ownership Reporting Compliance,”) and “User Guide” (under the subheading “2024 Annual Meetings,”) which information is incorporated herein by reference.

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

The following documents are available both on the Corporate Governance section of PG&E Corporation’s website (www.pgecorp.com/corp/about-us/corporate-governance.page) and on the Utility’s website (www.pge.com/en_US/about-pge/company-information/company-information.page, under the Corporate Governance and the Compliance & Ethics tabs): (1) PG&E Corporation’s 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 principal executive officers, principal 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 Sustainability and Governance Committee and the People and Compensation Committee.

If any amendments are made to, or any waivers are granted with respect to, provisions of the “code of ethics” by PG&E Corporation or the Utility and that apply to its respective principal executive officers, principal financial officers, or controllers, PG&E Corporation or the Utility, as appropriate, will post the amended code of ethics and any waivers at www.pgecorp.com/corp/about-us/compliance-ethics/program.page.

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 - 2022,” “Grants of Plan-Based Awards in 2022,” “Outstanding Equity Awards at Fiscal Year End - 2022,” “Option Exercises and Stock Vested during 2022,” “Pension Benefits - 2022,” “Non-Qualified Deferred Compensation - 2022,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability,” “Compensation of Non-Employee Directors,” and “Principal Executive Officers’ (PEO) Pay Ratio - 2022,” in the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility is set forth under the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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Equity Compensation Plan Information

The following table provides information as of December 31, 2022 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	37,654,078	(1)	$	40.04	(2)	53,350,101	(3)
Equity compensation plans not approved by shareholders	—		—			—
Total equity compensation plans	37,654,078	(1)	$	40.04	(2)	53,350,101	(3)

(1) Includes 160 phantom stock units, 9,658,300 restricted stock units and 19,313,387 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 2021, reflects the estimated payout percentage of zero percent for performance shares using a total shareholder return and financial metric, 200% for performance shares using operational metrics. The actual number of shares issued can range from zero percent to 200% of target depending on achievement of performance objectives. For performance-based stock options, amounts reflected in this table reflect actual payout of 102%. 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 2,195,834 options outstanding as of December 31, 2022.

(3) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, 2022. Stock-based awards granted under these plans include restricted stock units, performance shares, stock options, and phantom stock units. The PG&E Corporation 2014 LTIP, which became effective on May 12, 2014, authorized up to 17 million shares to be issued pursuant to awards granted under the LTIP. In addition, 5.5 million shares related to awards outstanding under the 2006 LTIP at December 31, 2013, or awards granted under the PG&E Corporation 2006 LTIP from January 1, 2014, through May 11, 2014, were cancelled, forfeited or expired and became available for issuance under the LTIP. A further 30 million shares were authorized for issuance under the PG&E Corporation 2014 LTIP on July 1, 2020, as part of the Plan. Lastly, an additional 44 million shares were authorized for issuance under the PG&E Corporation 2021 LTIP on June 1, 2021.

For more information, see Note 7 of the Notes to the Consolidated Financial Statements in 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 included under the headings “Related Party Transactions,” “Independence,” and “Committees and Memberships” in the Joint Proxy Statement relating to the 2023 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 included under 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 2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

196

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:

Consolidated Statements of Income for the Years Ended December 31, 2022, 2021, and 2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2022, 2021, and 2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2022 and 2021 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021, and 2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2022, 2021, and 2020 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2022, 2021, and 2020 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

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:

Condensed Financial Information of PG&E Corporation (“Parent”) as of December 31, 2022 and 2021 and for the Years Ended December 31, 2022, 2021, and 2020.

Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2022, 2021, and 2020.

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

Exhibit Number	Exhibit Description
3.1	Conformed Version of Amended and Restated Articles of Incorporation of PG&E Corporation, filed June 22, 2020, as amended by the Certificate of Amendment of Articles of Incorporation of PG&E Corporation, filed May 24, 2022
3.2	Bylaws of PG&E Corporation, Amended and Restated as of June 22, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 20, 2020 (File No. 1-12609), Exhibit 3.3)
3.3	Amended and Restated Articles of Incorporation of Pacific Gas and Electric Company, effective as of June 22, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.2)
3.4	Bylaws of Pacific Gas and Electric Company, Amended and Restated as of May 20, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 20, 2021 (File No. 1-2348), Exhibit 3.1)
4.1	Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.1)

197

4.2	First Supplemental Indenture, dated as of August 6, 2018, relating to the issuance by Pacific Gas and Electric Company of $500,000,000 aggregate principal amount of 4.25% Senior Notes due August 1, 2023 and $300,000,000 aggregate principal amount of 4.65% Senior Notes due August 1, 2028 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.2)
4.3	Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 2, 2020 (File No. 1-2348), Exhibit 4.5)
4.4	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), Exhibit 4.1)
4.5	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 to Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.6	Third Supplemental Indenture, dated as of March 3, 2008, relating to the issuance of $400,000,000 of Pacific Gas and Electric Company’s 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)
4.7	Sixth Supplemental Indenture, dated as of March 6, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.8	Eighth Supplemental Indenture, dated as of November 18, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
4.9	Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 aggregate principal amount of its 5.80% Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.10	Ninth Supplemental Indenture, dated as of June 3, 2021, relating to the $800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “First Mortgage Bonds”), between Pacific Gas and Electric Company and the Trustee (including the form of First Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 4.1)
4.11	Twelfth Supplemental Indenture, dated as of November 18, 2010, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of 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)
4.12	Thirteenth Supplemental Indenture, dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
4.13	Fourteenth Supplemental Indenture, dated as of September 12, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
4.14	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)

198

4.15	Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.16	Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of 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)
4.17	Nineteenth Supplemental Indenture, dated as of June 14, 2013, relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
4.18	Twentieth Supplemental Indenture, dated as of November 12, 2013, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
4.19	Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 1-2348), Exhibit 4.1)
4.20	Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)
4.21	Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)
4.22	Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.23	Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of $200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	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)
4.25	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)
4.26	Twenty-Ninth Supplemental Indenture, dated as of March 10, 2017, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.30% Senior Notes due March 15, 2027 and $200,000,000 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 March 10, 2017 (File No. 1-2348), Exhibit 4.1)

199

4.27	Thirtieth Supplemental Indenture, dated as of July 1, 2020, to the Amended and Restated Indenture, dated as of April 22, 2005, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.3)
4.28	Indenture, dated as of November 29, 2017, relating to the issuance of $500,000,000 aggregate principal amount of by Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 28, 2018, $1,150,000,000 aggregate principal amount of its 3.30% Senior Notes due December 1, 2027 and $850,000,000 aggregate principal amount of its 3.95% Senior Notes due December 1, 2047 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 29, 2017 (File No. 1-2348), Exhibit 4.1)
4.29	First Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of November 29, 2017, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.4)
4.30	Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.1)
4.31	First Supplemental Indenture, dated as of June 19, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the 1.75% First Mortgage Bonds due June 16, 2022, 2.10% First Mortgage Bonds due August 1, 2027, 2.50% First Mortgage Bonds due February 1, 2031, 3.30% First Mortgage Bonds due August 1, 2040 and 3.50% First Mortgage Bonds due August 1, 2050, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.2)
4.32	Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Senior Notes Collateral Bonds as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.6)
4.33	Third Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.75% First Mortgage Bond due July 1, 2028 and 3.45% First Mortgage Bond due July 1, 2025 (collectively, the “Short-Term Exchange Mortgage Bonds”) and 4.95% First Mortgage Bond due July 1, 2050 and 4.55% First Mortgage Bond due July 1, 2030 (collectively, the “Long-Term Exchange Mortgage Bonds”) between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Short-Term Exchange Mortgage Bonds and the Long-Term Exchange Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.1)
4.34	Fourth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.15% First Mortgage Bond due July 1, 2026 and 4.50% First Mortgage Bond due July 1, 2040 (collectively, the “Funded Debt Mortgage Bonds”) between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Funded Debt Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.2)
4.35	Fifth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the collateral bonds securing the $1,500,000,000 18-month term loan facility and the $1,500,000,000 364-day term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.7)
4.36	Sixth Supplemental Indenture, dated as of August 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 4.15)
4.37	Pledge Agreement, dated as of October 5, 2020, between Pacific Gas and Electric Company and MUFG Bank, Ltd. (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 4.1)

200

4.38	Eighth Supplemental Indenture, dated as of March 11, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $1,500,000,000 aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450,000,000 aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 Bonds and $450,000,000 aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041 Bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A.(including the form of First Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 8, 2021 (File No. 1-2348), Exhibit 4.1)
4.39	Ninth Supplemental Indenture, dated as of June 3, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “2028 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of 2028 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 4.1)
4.40	Tenth Supplemental Indenture, dated as of June 22, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of collateral bonds securing the revolving credit facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 4.1)
4.41	Eleventh Supplemental Indenture, dated as of October 29, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bond, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of collateral bond securing the 18-month term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-2348), Exhibit 4.2)
4.42	Twelfth Supplemental Indenture, dated as of November 15, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $300,000,000 aggregate principal amount of Floating Rate Mortgage Bonds due November 14, 2022 (the “Floating Rate Mortgage Bonds”) and the $900,000,000 aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 (the “2023 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of Floating Rate Mortgage Bonds and 2023 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 10, 2021 File No. 1-2348), Exhibit 4.1)
4.43	Thirteenth Supplemental Indenture, dated as of February 18, 2022, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of the Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 16, 2022 (File No. 1-2348), Exhibit 4.1)
4.44	Fourteenth Supplemental Indenture, dated as of April 4, 2022, relating to the collateral bond between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the form of collateral bond) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 4, 2022 (File No. 1-2348), Exhibit 4.1)
4.45	Fifteenth Supplemental Indenture, dated as of April 20, 2022, relating to the collateral bonds between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of collateral bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 4.1)
4.46	Sixteenth Supplemental Indenture, dated as of June 8, 2022, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of the Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 6, 2022 (File No. 1-2348), Exhibit 4.1)
4.47	Seventeenth Supplemental Indenture, dated as of October 4, 2022 to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-2348), Exhibit 4.3)
4.48	Eighteenth Supplemental Indenture, dated as of January 6, 2023, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 6, 2023 (File No. 1-2348), Exhibit 4.1)

201

4.49	Indenture, dated as of June 23, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 4.1)
4.50	First Supplemental Indenture, dated as of June 23, 2020, to the Indenture, dated as of June 23, 2020, relating to the 5.000% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and the 5.250% Senior Secured Notes due July 1, 2030 (the “2030 Notes”; together with the 2028 Notes, the “Notes”), among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., and JP Morgan Chase Bank N.A., as collateral agent (including the form of Notes for each series) (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.2)
4.51	Escrow Deposit and Disbursement Agreement, dated as of June 23, 2020, among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., as escrow agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.3)
4.52	Calculation Agency Agreement, dated as June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.3)
4.53	Escrow Deposit and Disbursement Agreement, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as escrow agent and as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.4)
4.54	Indenture, dated as of November 12, 2021, between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (including forms of the Senior Secured Recovery Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.1)
4.55	Series Supplement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.2)
4.56	Indenture, dated as of November 30, 2022, between PG&E Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A., (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-12609), Exhibit 4.1)
4.57	Series Supplement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-12609), Exhibit 4.2)
4.58	Indenture, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 4.1)
4.59	Series Supplement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 4.2)
4.60	Indenture, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 10, 2022 (File No. 1-2348), Exhibit 4.1)
4.61	Series Supplement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 10, 2022 (File No. 1-2348), Exhibit 4.2)
4.62 (a)	Description of PG&E Corporation’s Securities – Common Stock and Equity Units
4.62 (b)	Description of Pacific Gas and Electric Company’s Securities – Preferred Stock

202

10.1		Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)
10.2		Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)
10.3		Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, the several banks and other financial institutions or entities from time to time parties thereto, Mizuho Bank, Ltd., Royal Bank of Canada and Sumitomo Mitsui Banking Corporation, as joint lead arrangers and joint bookrunners and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to PG&E Corporation’s Form 8-K dated April 16, 2018 (File No. 1-12609), Exhibit 10.1)
10.4		Term Loan Agreement, dated as of February 23, 2018, among Pacific Gas and Electric Company, the several banks and other financial institutions or entities from time to time parties thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank National Association, as joint lead arrangers and joint bookrunners and The Bank of Tokyo-Mitsubishi UFJ, Ltd, as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 23, 2018 (File No. 1-02348), Exhibit 10.1)
10.5		Transmission Control Agreement among the California Independent System Operator Corporation (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.8)
10.6	*	Agreement to Enter Into Lease and Purchase Option, dated June 5, 2020, between Pacific Gas and Electric Company and TMG Bay Area Investments II, LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 5, 2020 (File No. 1-2348), Exhibit 10.1)
10.7	*	Office Lease, dated as of October 23, 2020, between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.12)
10.8		Calculation Agency Agreement, dated as of November 16, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 16, 2020 (File No. 1-2348), Exhibit 4.2)
10.9		Repricing Amendment, dated as of February 1, 2021, among PG&E Corporation, the Consenting Lenders, the New Lenders (each as defined therein) and JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)
10.10		Underwriting Agreement, dated as of February 16, 2022, among Pacific Gas and Electric Company, BofA Securities, Inc., J.P. Morgan Securities LLC, Goldman Sachs & Co. LLC and Mizuho Securities LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 16, 2022 (File No. 1-2348), Exhibit 1.1)

203

10.11	Underwriting Agreement, dated as of May 3, 2022, among PG&E Wildfire Recovery Funding LLC, Pacific Gas and Electric Company, Citigroup Global Markets Inc., Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC as representatives for the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 3, 2022 (File No. 1-2348), Exhibit 1.1)
10.12	Underwriting Agreement, dated as of June 6, 2022, among Pacific Gas and Electric Company, BMO Capital Markets Corp., BNP Paribas Securities Corp., BofA Securities, Inc., and Credit Suisse Securities (USA) LLC, as representatives of the several underwriters named therein (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 6, 2022 (File No. 1-2348), Exhibit 1.1)
10.13	Underwriting Agreement, dated as of July 13, 2022, among PG&E Wildfire Recovery Funding LLC, Pacific Gas and Electric Company and Citigroup Global Markets Inc., Barclays Capital Inc., and Goldman Sachs & Co. LLC, as representatives of the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 13, 2022 (File No. 1-2348), Exhibit 1.1)
10.14	Underwriting Agreement, dated as of November 18, 2022, among PG&E Recovery Funding LLC, Pacific Gas and Electric Company and Goldman Sachs & Co. LLC, Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2022 (File No. 1-2348), Exhibit 1.1)
10.15	Underwriting Agreement, dated as of January 4, 2023, among Pacific Gas and Electric Company, Barclays Capital Inc., Mizuho Securities USA LLC, MUFG Securities Americas Inc. and Wells Fargo Securities LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 6, 2023 (File No. 1-2348), Exhibit 1.1)
10.16	Equity Distribution Agreement, dated as of April 30, 2021, among PG&E Corporation, Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and forward sellers, and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (incorporated by reference to PG&E Corporation’s Form 8-K dated April 30, 2021 (File No. 1-12609), Exhibit 1.1)
10.17	Pledge Agreement, dated as of July 1, 2020, among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as collateral agent, revolving administrative agent and term administrative agent, The Bank of New York Mellon Trust Company, N.A., and the secured representatives party thereto from time to time (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.8)
10.18	Purchase Contract and Unit Agreement, dated as of July 1, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and attorney-in-fact for the holders from time to time as provided therein (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.9)
10.19	Custodial Agreement, dated as of July 1, 2020, between The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as custodian (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.12)
10.20	Registration Rights Agreement, dated as of August 6, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc., as representatives of the initial purchasers (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.5)
10.21	Registration Rights Agreement, dated as of July 1, 2020, between the Fire Victim Trust and PG&E Corporation (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.2)
10.22	Amended and Restated Registration Rights Agreement, dated as of July 8, 2021, between PG&E Corporation and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated July 8, 2021 (File No. 1-12609), Exhibit 4.1)
10.23	Credit Agreement, dated as of July 1, 2020, among PG&E Corporation, the several lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and JPMorgan Chase Bank, N.A., as collateral agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.3)

204

10.24	Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as administrative agent and collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 22, 2021 (File No. 1-12609), Exhibit 10.1)
10.25	Amendment No. 2 to Credit Agreement, dated as of October 4, 2022, among PG&E Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.2)
10.26	Term Loan Agreement, dated as of June 23, 2020, among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)
10.27	Repricing Amendment, dated as of February 1, 2021, among PG&E Corporation, the Consenting Lenders, the New Lenders (each as defined therein) and JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)
10.28	Credit Agreement, dated as of July 1, 2020, among Pacific Gas and Electric Company, the several lenders from time to time party thereto, JPMorgan Chase Bank, N.A. and Citibank, N.A., as co-administrative agents, and Citibank, N.A., as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.4)
10.29	Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as co-administrative agents and Citibank, N.A,, as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 10.2)
10.30	Amendment No. 2 to Credit Agreement, dated as of October 4, 2022, among Pacific Gas and Electric Company, the lenders party thereto, Citibank, N.A., as administrative agent and Citibank, N.A., as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-2348), Exhibit 10.3)
10.31	Term Loan Credit Agreement, dated as of July 1, 2020, among Pacific Gas and Electric Company, the several lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No.1-2348), Exhibit 10.4)
10.32	Amendment No. 1 to Credit Agreement, dated as of October 29, 2021, among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.5)
10.33	Amendment No. 2 to Credit Agreement, dated as of December 31, 2021, among Pacific Gas and Electric Company, the Consenting Lenders, the other Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2021 (File No. 1-2348), Exhibit 10.29)
10.34	Amendment No. 3 to Credit Agreement, dated as of February 8, 2022, among Pacific Gas and Electric Company, the Consenting Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2021 (File No. 1-2348), Exhibit 10.30)
10.35	Term Loan Credit Agreement, dated as of April 4, 2022, among Pacific Gas and Electric Company, the several lenders from time to time parties thereto and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 4, 2022 (File No. 1-2348), Exhibit 10.1)
10.36	Term Loan Credit Agreement, dated as of April 20, 2022, among Pacific Gas and Electric Company, the several lenders from time to time parties thereto and Bank of America, N.A., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.1)
10.37	Amendment No. 1 to Term Loan Credit Agreement, dated as of September 23, 2022, among Pacific Gas and Electric Company, the several lenders from time to time party thereto and Bank of America, N.A., as administrative agent

205

10.38	Purchase and Sale Agreement, dated as of October 5, 2020, between PG&E AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as Originator (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.1)
10.39	Amendment No. 1 to Purchase and Sale Agreement, dated as of January 14, 2021, between PG&E AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as Originator (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.75)
10.40	Amendment No. 2 to Purchase and Sale Agreement, dated as of March 18, 2022, among PG&E AR Facility, LLC, as buyer, Pacific Gas and Electric Company, as initial servicer and originator, JPMorgan Chase Bank, N.A., as a committed lender and group agent, Jupiter Securitization Company LLC, as a conduit lender, Mizuho Bank, Ltd., as a committed lender and group agent, BNP Paribas, as a committed lender and group agent, Starbird Funding Corporation, as a conduit lender, Victory Receivables Corporation, as a conduit lender, and MUFG Bank, Ltd., as a committed lender, group agent and administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.2)
10.41	Amendment No. 3 to Purchase and Sale Agreement, dated as of April 20, 2022, among PG&E AR Facility, LLC, as buyer, Pacific Gas and Electric Company, as initial Servicer and as an originator, the financial institutions party thereto and listed therein as committed lenders, conduit lenders, and group agents, and MUFG Bank, Ltd., as a Committed Lender, a Group Agent, and MUFG Bank, Ltd., Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.3)
10.42	Receivables Financing Agreement, dated as of October 5, 2020, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.2)
10.43	Amendment No. 1 to Receivables Financing Agreement, dated as of January 14, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.77)
10.44	Amendment No. 2 to Receivables Financing Agreement, dated as of February 12, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.78)
10.45	Amendment No. 3 to Receivables Financing Agreement, dated as of May 5, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.2)
10.46	Amendment No. 4 to Receivables Financing Agreement, dated as of September 15, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.3)
10.47	Amendment No. 5 to Receivables Financing Agreement, dated as of March 18, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-2348), Exhibit 10.4)
10.48	Amendment No. 6 to Receivables Financing Agreement, dated as of April 20, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.2)

206

10.49	Amendment No. 7 to Receivables Financing Agreement and Limited Waiver, dated as of June 21, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2022 (File No. 1-2348), Exhibit 10.6)
10.50	Amendment No. 8 to Receivables Financing Agreement, dated as of September 30, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.7)
10.51	Collection Account Intercreditor Agreement, dated as of October 5, 2020, among Pacific Gas and Electric Company, MUFG Bank, Ltd., and each trustee, indenture trustee, lender administrative agent, collateral agent, purchaser or other party described in Exhibit A therein (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.3)
10.52	Recovery Property Servicing Agreement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.1)
10.53	Recovery Property Purchase and Sale Agreement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.2)
10.54	Administration Agreement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.3)
10.55	Recovery Property Servicing Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.1)
10.56	Recovery Property Purchase and Sale Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.2)
10.57	Administration Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.3)
10.58	Recovery Property Servicing Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.1)
10.59	Recovery Property Purchase and Sale Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.2)
10.60	Administration Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.3)
10.61	Recovery Property Servicing Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer, (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.1)
10.62	Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.2)

207

10.63		Administration Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.3)
10.64		PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, dated as of July 8, 2021, among PG&E Corporation, Pacific Gas and Electric Company, PG&E ShareCo LLC and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated July 8, 2021 (File No. 1-12609), Exhibit 10.1)
10.65	**	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of June 3, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.9)
10.66	**	Consent to Recoupment of Excess Performance Share Units award for 2021 under the PG&E Corporation 2014 Long-Term Incentive Plan
10.67	**	Consent to Recoupment of Excess Performance Share Units, dated as of October 14, 2022, between PG&E Corporation and John R. Simon
10.68	**	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of February 15, 2023
10.69	**	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)
10.70	**	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective as of February 15, 2023
10.71	**	PG&E Corporation Short-Term Incentive Plan, as amended effective as of February 15, 2023.
10.72	**	Pacific Gas and Electric Company Officer Relocation Handbook, effective December 15, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.99)
10.73	**	Postretirement Life Insurance Plan of Pacific Gas and Electric Company, as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
10.74	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective February 6, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2014 (File No. 1-2348), Exhibit 10.37)
10.75	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective February 12, 2016, (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2016 (File No. 1-2348), Exhibit 10.4)
10.76	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective January 1, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.100)
10.77	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective January 1, 2020
10.78	**	Form of Stock Option Agreement for 2018 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, 2018 (File No. 1-12609), Exhibit 10.08)
10.79	**	Form of Restricted Stock Unit Agreement for 2021 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, 2021 File No. 1-12609), Exhibit 10.13)
10.80	**	Form of Restricted Stock Unit Agreement for 2022 grants to Non-Employee Directors under the PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2022 (File No. 1-12609), Exhibit 10.11)
10.81	**	Form of Performance Share Unit Agreement subject to customer experience, public safety and financial goals for 2021 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, 2021 (File No. 1-12609), Exhibit 10.14)

208

10.82	**	Form of Performance Share Unit Agreement subject to total shareholder return goals for 2021 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, 2021 (File No. 1-12609), Exhibit 10.15)
10.83	**	PG&E Corporation 2021 Long-Term Incentive Plan, as amended effective as of June 16, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2022 (File No. 1-12609), Exhibit 10.12)
10.84	**	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Restricted Stock Unit Award, as amended effective August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.8)
10.85	**	Form of PG&E Corporation 2021 Long-Term Incentive Plan Restricted Stock Unit Award, as amended effective August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.9)
10.86	**	Form of PG&E Corporation 2021 Long-Term Incentive Plan Performance Share Unit Award, as amended effective August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.10)
10.87	**	Amendment to 2014 PG&E Corporation Long-Term Incentive Plan Award Agreements and 2021 PG&E Corporation Long-Term Incentive Plan Award Agreements, dated as of August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.11)
10.88	**	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
10.89	**	PG&E Corporation 2010 Executive Stock Ownership Guidelines, as amended effective as of January 1, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.14)
10.90	**	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
10.91	**	Amendment to PG&E Corporation Golden Parachute Restriction Policy dated as of December 31, 2008 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
10.92	**	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No.1-12609), Exhibit 10.24)
10.93	**	Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated as of 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 10.01)
10.94	**	Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated as of 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)
10.95	**	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective February 19, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.119)
10.96	**	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated as of December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
10.97	**	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated as of July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
10.98	**	Form of Director and Officer Indemnification Agreement (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.08)
10.99	**	Non-Annual Restricted Stock Unit Award Agreement between Adam L. Wright and PG&E Corporation, dated as of March 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609, Exhibit 10.8)

209

10.100	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Marlene M. Santos, dated as of March 15, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.10)
10.101	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Christopher A. Foster, dated as of March 22, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.11)
10.102	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Julius Cox, dated as of March 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2021 (File No. 1-12609), Exhibit 10.92)
10.103	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Carla Peterman, dated as of June 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2021 (File No. 1-12609), Exhibit 10.93)
10.104	**	Consent to Amend Award Agreement, dated as of August 14, 2022, between PG&E Corporation and John R. Simon (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.12)
10.105	**	PG&E Corporation 2014 Long-Term Incentive Plan (as adopted effective May 12, 2014 and as last amended effective July 1, 2020) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.40)
10.106	**	PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to Appendix A to PG&E Corporation’s definitive proxy statement on Schedule 14A filed on April 8, 2021)
10.107	**	PG&E Corporation 2012 Officer Severance Policy, as amended effective November 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.13)
10.108	**	Form of Restricted Stock Unit Agreement under the PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.10)
10.109	**	Form of Performance Share Award Agreement under the PG&E Corporation 2021 Long-Term Incentive (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.11)
14		Employee Code of Conduct
21		Subsidiaries of the Registrant
23.1		PG&E Corporation Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
23.2		Pacific Gas and Electric Company 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

210

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*	In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request.
**	Management contract or compensatory plan, contract or arrangement.

211

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2022 to be signed on their behalf by the undersigned, thereunto duly authorized.

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.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant)		(Registrant)
	/s/ PATRICIA K. POPPE		/s/ ADAM L. WRIGHT
	Patricia K. Poppe		Adam L. Wright
By:	Chief Executive Officer	By:	Executive Vice President, Operations and Chief Operating Officer
Date:	February 22, 2023	Date:	February 22, 2023
			/s/ MARLENE M. SANTOS
			Marlene M. Santos
		By:	Executive Vice President and Chief Customer Officer
		Date:	February 22, 2023
			/s/ JASON M. GLICKMAN
			Jason M. Glickman
		By:	Executive Vice President, Engineering, Planning, and Strategy
		Date:	February 22, 2023

Signature	Title	Date
A.  Principal Executive Officers
/s/ PATRICIA K. POPPE	Chief Executive Officer	February 22, 2023
Patricia K. Poppe	(PG&E Corporation)

/s/ ADAM L. WRIGHT	Executive Vice President, Operations and Chief Operating Officer	February 22, 2023
Adam L. Wright	(Pacific Gas and Electric Company)

212

/s/ MARLENE M. SANTOS	Executive Vice President and Chief Customer Officer	February 22, 2023
Marlene M. Santos	(Pacific Gas and Electric Company)

/s/ JASON M. GLICKMAN	Executive Vice President, Engineering, Planning, and Strategy	February 22, 2023
Jason M. Glickman	(Pacific Gas and Electric Company)

B. Principal Financial Officers
/s/ CHRISTOPHER A. FOSTER	Executive Vice President and Chief Financial Officer	February 22, 2023
Christopher A. Foster	(PG&E Corporation)

/s/ STEPHANIE N. WILLIAMS	Vice President, Chief Financial Officer, and	February 22, 2023
Stephanie N. Williams	Controller (Pacific Gas and Electric Company)

C. Principal Accounting Officer
/s/ STEPHANIE N. WILLIAMS	Vice President, Chief Financial Officer, and	February 22, 2023
Stephanie N. Williams	Controller (Pacific Gas and Electric Company)

	C.  Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted)
*	/s/ RAJAT BAHRI	Director	February 22, 2023
	Rajat Bahri

*	/s/ CHERYL F. CAMPBELL	Director	February 22, 2023
	Cheryl F. Campbell	Chair of the Board (Pacific Gas and Electric Company)

*	/s/ KERRY W. COOPER	Director	February 22, 2023
	Kerry W. Cooper

*	/s/ JESSICA L. DENECOUR	Director	February 22, 2023
	Jessica L. Denecour

*	/s/ MARK E. FERGUSON III	Director	February 22, 2023
	Mark E. Ferguson III

*	/s/ ROBERT C. FLEXON	Director	February 22, 2023
	Robert C. Flexon	Chair of the Board (PG&E Corporation)

*	/s/ W. CRAIG FUGATE	Director	February 22, 2023
	W. Craig Fugate

213

*	/s/ ARNO L. HARRIS	Director	February 22, 2023
	Arno L. Harris

*	/s/ CARLOS M. HERNANNDEZ	Director	February 22, 2023
	Carlos M. Hernandez

*	/s/ MICHAEL R. NIGGLI	Director	February 22, 2023
	Michael R. Niggli

*	/s/ PATRICIA K. POPPE	Director	February 22, 2023
	Patricia K. Poppe

*	/s/ WILLIAM L. SMITH	Director	February 22, 2023
	William L. Smith

*	/s/ BENJAMIN F. WILSON	Director	February 22, 2023
	Benjamin F. Wilson

*	/s/ ADAM L. WRIGHT	Director (Pacific Gas and Electric Company)	February 22, 2023
	Adam L. Wright

*By:	/s/ JOHN R. SIMON	February 22, 2023
	John R. Simon, Attorney-in-Fact

214

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Administrative service revenue	$	109	$	118	$	127
Operating expenses	(193)		(124)		(103)
Interest income	3		—		—
Interest expense	(261)		(230)		(149)
Other income (expense)	(201)		(54)		13
Reorganization items, net	—		1		(1,649)
Equity in earnings of subsidiaries	2,154		137		411
Income (loss) before income taxes	1,611		(152)		(1,350)
Income tax benefit	(132)		(64)		(46)
Net Income (loss)	$	1,743	$	(88)	$	(1,304)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	$	21	$	7	$	(17)
Total other comprehensive income (loss)	21		7		(17)
Comprehensive Income (Loss)	$	1,764	$	(81)	$	(1,321)
Weighted Average Common Shares Outstanding, Basic (1)	2,235		2,463		1,257
Weighted Average Common Shares Outstanding, Diluted (1)	2,380		2,463		1,257
Net earnings (loss) per common share, basic	$	0.78	$	(0.05)	$	(1.05)
Net earnings (loss) per common share, diluted	$	0.73	$	(0.05)	$	(1.05)

(1) Includes 247,743,590 and 477,743,590 shares of common stock issued to ShareCo as of December 31, 2022 and 2021, respectively.

215

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED BALANCE SHEETS

	Balance at December 31,
(in millions)	2022		2021
ASSETS
Current Assets
Cash and cash equivalents	$	125	$	126
Advances to affiliates	46		21
Income taxes receivable	10		10
Other current assets	12		12
Total current assets	193		169
Noncurrent Assets
Equipment	—		2
Accumulated depreciation	—		(2)
Net equipment	—		—
Investments in subsidiaries	33,021		30,232
Other investments	160		181
Deferred income taxes	423		297
Total noncurrent assets	33,604		30,710
Total Assets	$	33,797	$	30,879
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current	27		27
Accounts payable – other	88		200
Other current liabilities	369		69
Total current liabilities	484		296
Noncurrent Liabilities
Long-term debt	4,588		4,592
Other noncurrent liabilities	134		168
Total noncurrent liabilities	4,722		4,760
Common Shareholders’ Equity
Common stock	36,132		35,129
Reinvested earnings	(7,542)		(9,286)
Accumulated other comprehensive income (loss)	1		(20)
Total common shareholders’ equity	28,591		25,823
Total Liabilities and Shareholders’ Equity	$	33,797	$	30,879

216

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2022		2021		2020
Cash Flows from Operating Activities:
Net income (loss)	$	1,743	$	(88)	$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	95		51		28
Equity in earnings of subsidiaries	(2,160)		(139)		(412)
Deferred income taxes and tax credits, net	(126)		(60)		(50)
Reorganization items, net (Note 2)	—		(32)		1,548
Current income taxes receivable/payable	—		2		—
Liabilities subject to compromise	—		—		12
Other	339		81		97
Net cash used in operating activities	(109)		(185)		(81)
Cash Flows From Investing Activities:
Investment in subsidiaries	(994)		—		(12,986)
Dividends received from subsidiaries (1)	1,275		—		—
Net cash provided by (used in) investing activities	281		—		(12,986)
Cash Flows From Financing Activities:
Bridge facility financing fees	—		—		(40)
Proceeds from issuance of long-term debt	—		—		4,660
Repayment of long-term debt	(28)		(28)		(664)
Proceeds from (repayments of) intercompany note from the Utility	(145)		145		—
Common stock issued	—		—		7,582
Equity Units issued	—		—		1,304
Other	—		(29)		—
Net cash provided by (used in) financing activities	(173)		88		12,842
Net change in cash and cash equivalents	(1)		(97)		(225)
Cash and cash equivalents at January 1	126		223		448
Cash and cash equivalents at December 31	$	125	$	126	$	223
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(233)	$	(207)	$	(105)
Income taxes, net	—		1		—
Supplemental disclosures of noncash investing and financing activities
Common stock issued in satisfaction of liabilities	—		—		8,276
Changes to PG&E Corporation common stock and treasury stock in connection     with the Share Exchange and Tax Matters Agreement	(2,337)		4,854		—

(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock.

217

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2022, 2021, and 2020

(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:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(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.

218

PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2022, 2021, and 2020

(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:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(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.

219

EX-3.1

EXHIBIT 3.1

CONFORMED VERSION OF
AMENDED AND RESTATED
ARTICLES OF INCORPORATION
OF
PG&E CORPORATION

(as amended)

    On June 22, 2020, PG&E Corporation (the “Corporation”) filed Amended and Restated Articles of Incorporation with the Secretary of State of the State of California. On May 24, 2022, PG&E Corporation filed a Certificate of Amendment of Articles of Incorporation with the Secretary of State of the State of California.

    FIRST: The name of the Corporation shall be

PG&E CORPORATION

    SECOND: The purpose of the Corporation is to engage in any lawful act or activity for which a corporation may be organized under the General Corporation Law of California other than the banking business, the trust company business or the practice of a profession permitted to be incorporated by the California Corporations Code.

THIRD:

I.    The Board of Directors of the Corporation (the “Board”) shall consist of such number of directors, not fewer than twelve (12) nor more than fifteen (15), as shall be fixed from time to time by the Board; provided that from and after the effective date of these Amended and Restated Articles of Incorporation until December 31, 2020, such minimum number of directors shall be nine (9).

II.    The Board by a vote of two-thirds of the whole Board may appoint from the directors an Executive Committee, which Committee may exercise such powers as may lawfully be conferred upon it by the Bylaws of the Corporation; provided, that the powers of the Executive Committee may not supersede the powers and responsibilities delegated to the Safety and Nuclear Oversight Committee in accordance with the charter of the Safety and Nuclear Oversight Committee. The Executive Committee may prescribe rules for its own government and its meetings may be held at such places within or without California as said Committee may determine or authorize.

    FOURTH: No shareholder may cumulate votes in the election of directors.

FIFTH: The liability of the directors of the Corporation for monetary damages shall be eliminated to the fullest extent permissible under California law.

SIXTH: The Corporation is authorized to provide indemnification of agents (as defined in Section 317 of the California Corporations Code) through bylaws, resolutions, agreements with agents, vote of shareholders or disinterested directors or otherwise, in excess of the indemnification otherwise permitted by Section 317 of the California Corporations Code, subject only to the applicable limits set forth in Section 204 of the California Corporations Code.

SEVENTH:

I.    The Corporation is authorized to issue two classes of shares, to be designated respectively Preferred Stock (“Preferred Stock”) and Common Stock (“Common Stock”). The total number of shares of capital stock that the Corporation is authorized to issue is 4,000,000,000, of which 400,000,000 shall be Preferred Stock and 3,600,000,000 shall be Common Stock. The Corporation shall not issue nonvoting equity securities (as such term is defined in Section 101(16) of the United States Bankruptcy Code (“Bankruptcy Code”)) to the extent prohibited by Section 1123(a)(6) of the Bankruptcy Code for so long as such Section 1123(a)(6) is in effect and applicable to the Corporation.

II.    The Preferred Stock may be issued in any number of series, as determined by the Board. The Board may by resolution fix the designation and number of shares of any such series and, subject to Section I of Article Seventh, may determine, alter, or revoke the rights, preferences, privileges, and restrictions

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[[DMS:5334890v17:5/21/2020 12:29:33 AM

pertaining to any wholly unissued class or series of shares. The Board may thereafter in the same manner increase or decrease the number of shares of any such series (but not below the number of shares of that series then outstanding). If the number of shares of any such series shall be so decreased, the shares constituting such decrease shall resume the status that they had prior to the adoption of the resolution originally fixing the number of shares of such series.

EIGHTH:

The Board, when evaluating any proposal or offer which would involve (i) a merger or consolidation of the Corporation or any of its subsidiaries with another person, (ii) a sale of all or substantially all of the assets of the Corporation or any of its subsidiaries, (iii) a tender offer or exchange offer for any capital stock of the Corporation or any of its subsidiaries, or (iv) any similar transaction, shall give due consideration to all factors they may consider relevant. Such factors may include, without limitation, (a) the adequacy, both in amount and form, of the consideration offered in relation not only to the current market price of the Corporation’s outstanding securities, but also the current value of the Corporation in a freely negotiated transaction with other potential acquirers and the Board’s estimate of the Corporation’s future value (including the unrealized value of its properties, assets and prospects) as an independent going concern, (b) the financial and managerial resources and future prospects of the acquirer, and (c) the legal, economic, environmental, regulatory and social effects of the proposed transaction on the Corporation’s and its subsidiaries’ employees, customers, suppliers and other affected persons and entities and on the communities and geographic areas in which the Corporation and its subsidiaries operate, provide utility service or are located, and in particular, the effect on the Corporation’s and its subsidiaries’ ability to safely and reliably meet any public utility obligations they may have at reasonable rates.

NINTH:

Restrictions on Transfer of Securities.To ensure the preservation of certain tax attributes for the benefit of the Corporation and its shareholders, certain restrictions on the transfer of Corporation Securities (as defined below) are hereby established as more fully set forth in this Article Ninth.

    (a)    Definitions. For purposes of this Article Ninth, the following terms shall have the meanings indicated (and any references to any portions of Treasury Regulation Sections 1.382-2T, 1.382-3, 1.382-4 and 1.1502-92 shall include any successor provisions):

“Acquiring Group” means any group of Persons where one or more Persons in such group acquires or seeks to acquire beneficial ownership of Corporation Securities and one or more other Persons in such group acquires or seeks to acquire beneficial ownership of Company Group Securities other than Corporation Securities (other than an indirect acquisition solely as a result of the acquisition of Corporation Securities), such as outstanding shares of Utility Preferred Stock, pursuant to a plan or arrangement within the meaning of Treasury Regulations Section 1.1502-92(c)(3)(i).

“Agent” means an agent designated by the Board.

“Company Group” means the Corporation and its consolidated subsidiaries for U.S. federal income tax purposes.

“Company Group Securities” means (i) Corporation Securities, (ii) Utility Securities (other than Utility Securities held by the Corporation), and (iii) any other interests of a member of the Company Group designated as stock by the Board as disclosed in a United States Securities and Exchange Commission (the “SEC”) filing by the Corporation.

“Corporation Securities” means (i) shares of Common Stock, (ii) shares of Preferred Stock (other than preferred stock described in Section 1504(a)(4) of the Tax Code) and (iii) any other interest designated as “stock” of the Corporation by the Board, as disclosed in an SEC filing by the Corporation.

“Excess Securities” means Corporation Securities that are the subject of the Prohibited Transfer.

“Percentage Stock Ownership” means the percentage stock ownership interest in the Corporation of any Person for purposes of Section 382 of the Tax Code as determined in accordance with Treasury Regulation Sections 1.382-2T(g), (h), (j) and (k) and 1.382-4 (i.e., the constructive ownership and attribution rules of the regulations); provided, that (1) if any Person is a member of an Acquiring Group, such Person’s Percentage Stock Ownership in the Corporation shall take into account any ownership of additional shares of stock treated as issued by the Corporation under Treasury Regulations Section 1.1502-92 as a result of the Acquiring Group’s planned or actual acquisition of the Company Group Securities (applying such sections with reference to the Corporation as the common parent, including under

2

supplemental rules for determining an ownership change and treating the Corporation as having “actual knowledge” of all plans and acquisitions of Company Group Securities for purposes of applying Treasury Regulations Section 1.1502-92(c)(2)(iii)), (2) for purposes of applying Treasury Regulation Section 1.382-2T(k)(2), the Corporation shall be treated as having “actual knowledge” of the beneficial ownership of all outstanding Company Group Securities that would be attributed to any individual or entity, and (3) for the sole purpose of determining the Percentage Stock Ownership of any Person that is an entity (and not for the purpose of determining the Percentage Stock Ownership of any other Person), Company Group Securities held by such Person shall not be treated as no longer owned by such Person pursuant to Treasury Regulation Section 1.382-2T(h)(2)(i)(A).

“Person” means any individual, partnership, joint venture, limited liability company, firm, corporation, unincorporated association or organization, trust or other entity, provided, that, for all purposes of this Article Ninth, any group of such “Persons” having a formal or informal understanding among themselves to make a “coordinated acquisition” of shares within the meaning of Treasury Regulation Section 1.382-3(a)(1) or who are otherwise treated as an “entity” within the meaning of Treasury Regulation Section 1.382-3(a)(1) shall be treated as an “entity,” and references to any entity shall include any successor (by merger or otherwise) of any such entity.

“Prohibited Distributions” means any dividends or other distributions that were received by the Purported Transferee from the Corporation with respect to the Excess Securities received by a Purported Transferee.

“Prohibited Transfer” means any purported Transfer of Corporation Securities to the extent that such Transfer is prohibited and/or void under this Article Ninth.

“Restriction Release Date” means the earliest of:

(i)    the repeal, amendment or modification of Section 382 of the Tax Code (and any comparable successor provisions) in such a way as to render the restrictions imposed by Section 382 of the Tax Code no longer applicable to the Corporation;

(ii)    the beginning of a taxable year of the Company Group (or any successor thereof) in which the Board determined that no Tax Benefits are available;

(iii)     the date selected by the Board if the Board determines that the limitation amount imposed by Section 382 of the Tax Code as of such date in the event of an “ownership change” of the Corporation (as defined in Section 382 of the Tax Code and Treasury Regulation Sections 1.1502-91 et seq.) would not be materially less than the net operating loss carryforwards or “net unrealized built-in loss” (within the meaning of Section 382 of the Tax Code and Treasury Regulation Sections 1.1502-91 et seq.) of the Corporation; and

(iv)    the date selected by the Board if the Board determines that it is in the best interests of the Corporation’s shareholders for the restrictions set forth in section (b) of this Article Ninth to be removed or released.

“Substantial Shareholder” means a Person with a Percentage Stock Ownership of 4.75% or more.

“Tax Benefit” means any net operating loss carryovers, capital loss carryovers, excess interest deduction carryovers, general business credit carryovers, alternative minimum tax credit carryovers and foreign tax credit carryovers, as well as any loss or deduction attributable to a “net unrealized built-in loss” within the meaning of Section 382 of the Tax Code, of the Company Group or any member thereof.

“Tax Code” means the Internal Revenue Code of 1986, as amended from time to time.

“Transfer” means the acquisition, directly or indirectly, of ownership of Corporation Securities by any means – including, without limitation, (i) the creation or grant of any pledge (or other security interest), right or option with respect to Corporation Securities, including an option within the meaning of Treasury Regulation Section 1.382-4(d)(9), (ii) the exercise of any such pledge, right or option, or (iii) any other transaction treated under the applicable rules under Section 382 of the Tax Code as a direct or indirect acquisition (including the acquisition of an ownership interest in a Substantial Shareholder), provided, that “Transfer” shall not include any such acquisition unless, as a result, there would be an increase in any Person’s Percentage Stock Ownership .

“Trust Subsidiary” has the meaning provided for in section (c)(i)(A) of this Article Ninth.

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“Utility” means Pacific Gas and Electric Company.

“Utility Charter” means the Amended and Restated Articles of Incorporation of Utility.

“Utility Preferred Stock” means preferred stock issued by Utility (other than preferred stock described in Section 1504(a)(4) of the Tax Code).

“Utility Securities” means (i) shares of common stock issued by Utility, (ii) Utility Preferred Stock, and (iii) any other interest designated as “stock” of Utility by the Board, as disclosed in an SEC filing by Utility.

(b)    Prohibited Transfers. Any attempted Transfer of Corporation Securities prior to the Restriction Release Date, or any attempted Transfer of Corporation Securities pursuant to an agreement entered into prior to the Restriction Release Date, shall be prohibited and void ab initio insofar as it purports to transfer ownership or rights in respect of such stock to the purported transferee of a Prohibited Transfer (a “Purported Transferee”) to the extent that, as a result of such Transfer (or any series of Transfers of which such Transfer is a part), either (1) any Person shall become a Substantial Shareholder other than by reason of Treasury Regulation Section 1.382-2T(j)(3) or (2) the Percentage Stock Ownership interest of any Substantial Shareholder shall be increased. Nothing in this Article Ninth shall preclude the settlement of any transaction with respect to Corporation Securities entered into through the facilities of a national securities exchange; provided, however, that such a transaction shall still constitute a Prohibited Transfer and the Corporation Securities and parties involved in such transaction shall remain subject to the provisions of this Article Ninth in respect of such transaction. In the event that there is an attempted concurrent Transfer of both Corporation Securities and Utility Securities that would be a Prohibited Transfer hereunder and under the Utility Charter (as determined without regard to this sentence), the Prohibited Transfer provisions of the Utility Charter shall be applied first rendering such attempted Transfer of the Utility Securities null and void to the extent necessary, and this section (b) of this Article Ninth shall then be applied to the attempted Transfer of the Corporation Securities the extent necessary.

(c)    Exceptions; Authorized Transfers.

(i)    The restrictions set forth in section (b) of this Article Ninth shall not apply to the acquisition of Corporation Securities by the “Fire Victim Trust” as defined in and in accordance with the provisions of the Plan or an attempted Transfer (1) if the transferor or the transferee obtains the prior written approval of the Board or a committee thereof in accordance with section (c)(ii) of this Article Ninth below, or (2) if such Transfer is (A) made as part of certain transactions approved by the Board in accordance with section (c)(iii) of this Article Ninth, or (B) to the Corporation or Utility. Notwithstanding anything to the contrary herein, (i) a sale, disposition or other transfer of Corporation Securities by the Fire Victim Trust or a Trust Subsidiary to a direct Public Group (including a new direct Public Group created under Treasury Regulation § 1.382-2T(j)(3)(i)), including, without limitation, pursuant to customary agreements with and between underwriters and selling group members with respect to a bona fide public offering, shall be permitted; and (ii) the provisions of Treasury Regulation §1.382-3(j)(13) (regarding deemed proportionate acquisitions by existing Public Groups) shall not create any limitation on a sale, disposition, or other transfer of Corporation Securities by the Fire Victim Trust or a Trust Subsidiary to any Public Group otherwise permitted under this Article Ninth; provided¸ that no transaction under this sentence shall be permitted if or to the extent a public shareholder (as defined in Treasury Regulation §1.382-2T(f)(11)) would become a Substantial Shareholder or a Substantial Shareholder would increase its Percentage Stock Ownership in violation of this Article Ninth. “Public Group” has the meaning set forth in Treasury Regulation § 1.382-2T(f)(13) and, for the avoidance of doubt, is not a “Person” for purposes of this Article Ninth. Notwithstanding any other restriction set forth in this Article Ninth, the Fire Victim Trust shall be permitted to:

(A)    Sell, dispose of, or otherwise transfer Corporation Securities to a subsidiary that is, directly or indirectly, owned 100% by the Fire Victim Trust (a “Trust Subsidiary”);

(B)    Pledge, or enter into security arrangements with respect to, Corporation Securities or the equity interests of a Trust Subsidiary, provided that the creation or exercise of such pledge or security arrangements would not result in any Person becoming a Substantial Shareholder or cause the Percentage Stock Ownership of any Substantial Shareholder to be increased; and

(C)    Issue, transfer or structure an option with respect to the Corporation Securities or the equity interests of a Trust Subsidiary, provided that the creation or

4

exercise of such option would not result in any Person becoming a Substantial Shareholder or cause the Percentage Stock Ownership of any Substantial Shareholder to be increased.

The Board shall not take any action to cause any of (A)-(C) to constitute or be deemed to constitute a Prohibited Transfer.

(ii)    The restrictions contained in this Article Ninth are for the purposes of reducing the risk that any “ownership change” (as defined in Section 382 of the Tax Code) with respect to the Company Group may limit the Company Group’s ability to utilize its Tax Benefits. In connection therewith, and to provide for effective policing of these provisions, any Person or Acquiring Group that desires to acquire Corporation Securities in an otherwise Prohibited Transfer (a “Requesting Person”) shall, prior to the date of such transaction for which the Requesting Person seeks authorization (the “Proposed Transaction”), request in writing (a “Request”) that the Board review the Proposed Transaction and authorize or not authorize the Proposed Transaction in accordance with this section (c) of this Article Ninth. A Request shall be mailed or delivered to the Secretary of the Corporation at the Corporation’s principal place of business. Such Request shall be deemed to have been received by the Corporation when actually received by the Corporation. A Request shall include: (1) the name, address and telephone number of the Requesting Person; (2) the Percentage Stock Ownership then beneficially owned by the Requesting Person (without regard to the ownership of Company Group Securities in any subsidiary of the Corporation), the then number and percentage (by class) of any Company Group Securities in any subsidiary of the Corporation beneficially owned by the Requesting Person, and the then number and percentage (by class) of any Company Group Securities in any subsidiary of the Corporation beneficially owned by any Acquiring Group of which the Requesting Person is a member (and the names and relationship of the Persons within the Acquiring Group); (3) a reasonably detailed description of the Proposed Transaction or Proposed Transactions for which the Requesting Person seeks authorization; and (4) a request that the Board authorize the Proposed Transaction pursuant to this section (c) of this Article Ninth. The Board shall respond to each Request within 20 business days of receiving such Request, and the failure of the Board to respond during such 20 business day period shall be deemed to be a consent to the Transfer; provided, that, the Board may respond by requesting additional information, indicating it requires additional time to consider the Request or in another reasonable manner. The Board shall authorize a Proposed Transaction unless the Board determines in good faith that the Proposed Transaction, considered alone or with other transactions (including, without limitation, past, concurrent, contemplated or anticipated transactions (whether by the Corporation, by another Person pursuant to a Request or otherwise, whether or not the transaction was a Prohibited Transfer) and transactions involving Company Group Securities (including issuances and redemptions) not currently contemplated but which, in the business judgment of the Board, the Corporation should retain the flexibility to pursue) would create a material risk that the Tax Benefits may be jeopardized as a result of the application of Sections 382 and 383 of the Tax Code, allowing for a reasonable margin of safety; provided, that, if multiple Requests are submitted to the Board at approximately the same time and all such Requests would not be approved pursuant to this sentence, the Board may determine any reasonable method to apply the provisions of this sentence to such Requests. Any determination by the Board not to authorize a Proposed Transaction shall cause such Proposed Transaction to continue to be treated as a Prohibited Transfer. The Board may impose any conditions that it deems reasonable and appropriate in connection with authorizing any Proposed Transaction, including requiring an affidavit or representations from such Requesting Person or opinions of counsel to be rendered by counsel selected by the Requesting Person (and reasonably acceptable to the Board), in each case, as to such matters as the Board may reasonably determine with respect to the preservation of the Tax Benefits. Any Requesting Person who makes a Request to the Board shall reimburse the Corporation, within 30 days of demand therefor, for all reasonable out-of-pocket costs and expenses incurred by the Corporation with respect to evaluating the Proposed Transaction of such Requesting Person, including, without limitation, the Corporation’s reasonable costs and expenses incurred in determining whether to authorize the Proposed Transaction, which costs may include, but are not limited to, any reasonable expenses of counsel and/or tax advisors engaged by the Board to advise the Board or deliver an opinion thereto. The Board may require, as a condition to its consideration of the Request, that the Requesting Person execute an agreement in form and substance reasonably satisfactory to the Corporation providing for the reimbursement of such costs and expenses. Any authorization of the Board hereunder may be given prospectively or retroactively.

(iii)    The Board may determine that the restrictions set forth in section (b) of this Article Ninth shall not apply to any particular transaction or transactions, whether or not a request has been made to the Board, including a Request pursuant to this section (c) of this Article Ninth, subject to any conditions that it deems reasonable and appropriate in connection therewith. Any determination of the Board hereunder may be made prospectively or retroactively.

5

(iv)    The Board or any committee of the Board, to the fullest extent permitted by law, may exercise the authority granted by this Article Ninth through duly authorized officers or agents of the Corporation. Nothing in this section (c) of this Article Ninth shall be construed to limit or restrict the Board in the exercise of its fiduciary duties under applicable law.

(d)    Legend; Notation. The Board may require that any certificates representing shares of Corporation Securities issued prior to the Restriction Release Date shall contain a conspicuous legend in substantially the following form, or as may otherwise be determined by the Board, evidencing the restrictions set forth in this Article Ninth:

“THE AMENDED AND RESTATED ARTICLES OF INCORPORATION OF THE CORPORATION, AS THE SAME MAY BE AMENDED AND RESTATED FROM TIME TO TIME (THE “ARTICLES OF INCORPORATION”), CONTAIN CERTAIN RESTRICTIONS PROHIBITING THE TRANSFER (AS DEFINED IN THE ARTICLES OF INCORPORATION) OF CORPORATION SECURITIES (AS DEFINED IN THE ARTICLES OF INCORPORATION) WITHOUT THE PRIOR AUTHORIZATION IN ACCORDANCE WITH THE ARTICLES OF INCORPORATION IF SUCH TRANSFER MAY AFFECT THE PERCENTAGE OF STOCK OF THE CORPORATION (WITHIN THE MEANING OF SECTION 382 OF THE INTERNAL REVENUE CODE OF 1986, AS AMENDED FROM TIME TO TIME, AND THE TREASURY REGULATIONS PROMULGATED THEREUNDER) THAT IS TREATED AS OWNED BY A “SUBSTANTIAL SHAREHOLDER” AS DEFINED IN THE ARTICLES OF INCORPORATION. A COMPLETE AND CORRECT COPY OF THE ARTICLES OF INCORPORATION SHALL BE FURNISHED FREE OF CHARGE TO THE HOLDER OF RECORD OF THIS CERTIFICATE UPON WRITTEN REQUEST TO THE SECRETARY OF THE CORPORATION.”

The Corporation shall have the power to make appropriate notations upon its stock transfer records and to instruct any transfer agent, registrar, securities intermediary or depository with respect to the requirements of this Article Ninth for any uncertificated Corporation Securities or Corporation Securities held in an indirect holding system, and the Corporation shall provide notice of the restrictions on transfer and ownership to holders of uncertificated shares in accordance with applicable law.

(e)    Treatment of Excess Securities.

(i)    No officer, employee or agent of the Corporation shall record any Prohibited Transfer, and the Purported Transferee shall not be recognized as a shareholder of the Corporation for any purpose whatsoever in respect of the Excess Securities. Until the Excess Securities are acquired by another Person in a Transfer that is not a Prohibited Transfer, the Purported Transferee shall not be entitled with respect to such Excess Securities to any rights of shareholders of the Corporation, including, without limitation, the right to vote such Excess Securities and to receive dividends or distributions, whether liquidating or otherwise, in respect thereof, if any. Once the Excess Securities have been acquired in a Transfer that is not a Prohibited Transfer, Corporation Securities shall cease to be Excess Securities. For this purpose, any transfer of Excess Securities not in accordance with the provisions of this section (e) of this Article Ninth shall also be a Prohibited Transfer.

(ii)    If the Board determines that a Transfer of Corporation Securities constitutes a Prohibited Transfer pursuant to section (b) of this Article Ninth, then, upon written demand by the Corporation, the Purported Transferee shall transfer or cause to be transferred any certificate or other evidence of ownership of the Excess Securities within the Purported Transferee’s possession or control, together with any Prohibited Distributions, to the Agent. The Agent shall thereupon sell to a buyer or buyers, which may include the Corporation, the Excess Securities transferred to it in one or more arm’s-length transactions (over the New York Stock Exchange or other national securities exchange on which Corporation Securities may be traded, if possible, or otherwise privately); provided, however, that the Agent shall use reasonable efforts to effect such sale or sales in an orderly fashion and shall not be required to effect any such sale within any specific time frame if, in the Agent’s discretion, such sale or sales would disrupt the market for Corporation Securities or otherwise would adversely affect the value of Corporation Securities. If the Purported Transferee has resold the Excess Securities before receiving the Corporation’s demand to surrender Excess Securities to the Agent, the Purported Transferee shall be deemed to have sold the Excess Securities for the Agent, and shall be required to transfer to the Agent any Prohibited Distributions and proceeds of such sale, except to the extent that the Corporation grants written permission to the Purported Transferee to retain all or a portion of such sales proceeds to the extent not exceeding the amount that the Purported Transferee would have received from the Agent pursuant to section (e)(iii) of this Article Ninth if the Agent rather than the Purported Transferee had resold the Excess Securities.

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(iii)    The Agent shall apply any proceeds or any other amounts received by it in accordance with section (e)(ii) of this Article Ninth as follows: (A) first, such amounts shall be paid to the Agent to the extent necessary to cover its reasonable costs and expenses incurred in connection with its duties hereunder; (B) second, any remaining amounts shall be paid to the Purported Transferee, up to the amount paid by the Purported Transferee for the Excess Securities (or in the case of any Prohibited Transfer by gift, devise or inheritance or any other Prohibited Transfer without consideration, the fair market value, (1) calculated on the basis of the closing market price for Corporation Securities on the day before the Prohibited Transfer, (2) if Corporation Securities are not listed or admitted to trading on any stock exchange but are traded in the over-the-counter market, calculated based upon the difference between the highest bid and lowest asked prices, as such prices are reported by the relevant inter-dealer quotation service or any successor system on the day before the Prohibited Transfer or, if none, on the last preceding day for which such quotations exist, or (3) if Corporation Securities are neither listed nor admitted to trading on any stock exchange nor traded in the over-the-counter market, then as determined in good faith by the Board), which amount (or fair market value) shall be determined at the discretion of the Board; and (C) third, any remaining amounts, subject to the limitations imposed by the following proviso, shall be paid to one or more organizations qualifying under Section 501(c)(3) of the Tax Code (or any comparable successor provision) selected by the Board; provided, however, that if the Excess Securities (including any Excess Securities arising from a previous Prohibited Transfer not sold by the Agent in a prior sale or sales) represent a 4.75% or greater Percentage Stock Ownership, then any such remaining amounts to the extent attributable to the disposition of the portion of such Excess Securities exceeding a 4.75% Percentage Stock Ownership interest shall be paid to two or more organizations qualifying under Section 501(c)(3) of the Tax Code selected by the Board, such that no organization qualifying under Section 501(c)(3) of the Tax Code shall be deemed to possess a Percentage Stock Ownership in excess of 4.75%. The recourse of any Purported Transferee in respect of any Prohibited Transfer shall be limited to the amount payable to the Purported Transferee pursuant to clause (B) of the preceding sentence. In no event shall the proceeds of any sale of Excess Securities pursuant to this section (e) of this Article Ninth inure to the benefit of the Corporation.

(iv)    In the event of any Transfer that does not involve a transfer of Corporation Securities within the meaning of the laws of the State of California, but that would cause a Substantial Shareholder to violate any restriction on Transfer provided for in section (b) of this Article Ninth, the application of sections (e)(ii) and (e)(iii) of this Article Ninth shall be modified as described in this section (e)(iv) of this Article Ninth. In such case, no such Substantial Shareholder shall be required to dispose of any interest that is not a Corporation Security, but such Substantial Shareholder and/or any Person or Acquiring Group whose ownership of Corporation Securities is attributed to or taken into account with respect to such Substantial Shareholder shall, in the case of section (e)(ii) of this Article Ninth, be deemed to have disposed of and shall be required to dispose of sufficient Corporation Securities (which Corporation Securities shall be disposed of in the inverse order in which they were acquired) to cause such Substantial Shareholder, following such disposition, not to be in violation of this Article Ninth. Such disposition or process shall be deemed to occur simultaneously with the Transfer giving rise to the application of this provision, and such number of Securities that are deemed to be disposed of shall be considered Excess Securities and shall be disposed of through the Agent as provided in sections (e)(ii) and (e)(iii) of this Article Ninth, except that the maximum aggregate amount payable either to such Substantial Shareholder, or to such other Person or Acquiring Group that was the direct holder of such Excess Securities, in connection with such sale shall be the fair market value of such Excess Securities at the time of the purported Transfer. All such reasonable expenses incurred by the Agent in disposing of such Excess Securities shall be paid out of any amounts due such Substantial Shareholder or such other Person or Acquiring Group. The purpose of this section (e)(iv) of this Article Ninth is to extend the restrictions in sections (b) and (e)(ii) of this Article Ninth to situations in which there is a Prohibited Transfer without a direct Transfer of Securities, and this section (e)(iv) of this Article Ninth, along with the other provisions of this Article Ninth, shall be interpreted to produce the same results, with differences as the context requires, as a direct Transfer of Corporation Securities.

(v)    If the Purported Transferee fails to surrender the Excess Securities or the proceeds of a sale thereof to the Agent within 30 days from the date on which the Corporation makes a written demand pursuant to section (e)(ii) of this Article Ninth, then the Corporation shall use its best efforts to enforce the provisions hereof, including the institution of legal proceedings to compel the surrender. Nothing in this section (e)(v) of this Article Ninth shall (A) be deemed to be inconsistent with any Transfer of the Excess Securities provided in this Article Ninth to be void ab initio, or (B) preclude the Corporation in its discretion from immediately instituting legal proceedings without a prior demand. The Board or a committee thereof may authorize such additional actions as it deems advisable to give effect to the provisions of this Article Ninth.

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(vi)    The Corporation shall make the written demand described in section (e)(ii) of this Article Ninth within 30 days of the date on which the Board determines that the attempted Transfer would result in Excess Securities; provided, however, that, if the Corporation makes such demand at a later date, the provisions of this Article Ninth shall apply nonetheless. No failure by the Corporation to act within the time periods set forth in section(e) of this Article Ninth shall constitute a waiver or loss of any right of the Corporation under this Article Ninth.

(f)    Obligation to Provide Information. Any Person that is a beneficial, legal or record holder of Corporation Securities or a member of an Acquiring Group, and any proposed transferor or transferee and any Person controlling, controlled by or under common control with the proposed transferor or transferee, shall as and to the extent reasonably requested in writing by the Corporation, use commercially reasonable efforts promptly to provide such information the Corporation may request as may be necessary from time to time in order to determine compliance with this Article Ninth or the status of the Tax Benefits.  For the avoidance of doubt, notwithstanding anything to the contrary in this section (f) of this Article Ninth, in no event will any Person have any obligation to provide any such information that such Person determines, in its reasonable judgment, it is legally or contractually prohibited from disclosing; provided, that the Board may decline to authorize a Proposed Transaction, notwithstanding any provision of section (c)(ii) of this Article Ninth to the contrary, if any Requesting Person does not provide any information reasonably requested by the Corporation.

(g)    Board Authority.

(i)    The Board or any committee thereof shall have the power to interpret or determine in its sole discretion all matters necessary for assessing compliance with this Article Ninth, including, without limitation, (i) the identification of Substantial Shareholders or Acquiring Groups, (ii) whether a Transfer is a Prohibited Transfer, (iii) whether to exempt a Transfer from the restrictions of section (b) of this Article Ninth, (iv) the Percentage Stock Ownership of any Substantial Shareholder, (v) whether an instrument constitutes a Company Group Security, (vi) the amount (or fair market value) due to a Purported Transferee pursuant to clause (B) of section (e)(iii) of this Article Ninth, and (vii) any other matters which the Board or such committee determines to be relevant; and the good faith determination of the Board or such committee on such matters shall be conclusive and binding for all the purposes of this Article Ninth.

(ii)    In addition, the Board or any committee thereof may, to the extent permitted by law, from time to time establish, modify, amend or rescind bylaws, regulations and procedures of the Corporation not inconsistent with the provisions of this Article Ninth for purposes of determining whether any Transfer of Corporation Securities would jeopardize the Company Group’s ability to preserve and use the Tax Benefits and for the application, administration and implementation of this Article Ninth.

(iii)    Nothing contained in this Article Ninth shall limit the authority of the Board or a committee thereof to take such other action to the extent permitted by law as it deems necessary or advisable to protect the Company Group and the Corporation’s shareholders in preserving the Tax Benefits, including the implementation of restrictions on dispositions or sales of Corporation Securities that result in a decrease of a Substantial Shareholder’s Percentage Stock Ownership. Without limiting the generality of the foregoing, in the event of a change in law making one or more of the following actions necessary or desirable, the Board or any committee thereof may, by adopting a written resolution, (A) modify the ownership interest percentage in the Corporation or the Persons covered by this Article Ninth, (B) modify the definitions of any terms set forth in this Article Ninth or (C) modify the terms of this Article Ninth as appropriate, in each case, in order to prevent an ownership change for purposes of Section 382 of the Tax Code as a result of any changes in applicable Treasury Regulations or otherwise; provided, however, that the Board or committee shall not cause there to be such modification unless it determines that such action is reasonably necessary or advisable to preserve the Tax Benefits or that the continuation of these restrictions is no longer reasonably necessary for the preservation of the Tax Benefits. Shareholders of the Corporation shall be notified of such determination through a filing with the SEC or such other method of notice as the Corporation deems appropriate.

(iv)    In the case of an ambiguity in the application of any of the provisions of this Article Ninth, including any definition used herein, the Board shall have the power to determine the application of such provisions. In the event this Article Ninth requires an action by the Board but fails to provide specific guidance with respect to such action, the Board or any committee thereof shall have the power to determine the action to be taken. All such actions, calculations, interpretations and determinations that are done or made by the Board shall be conclusive and binding on the Corporation, the Agent and all other parties for all other purposes of this Article Ninth. The Board may delegate all or any portion of its duties and powers under this Article Ninth to a committee of the Board as it deems necessary or advisable, and, to the Board and such committee may exercise the authority granted by this Article Ninth through

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duly authorized officers or agents of the Corporation. Nothing in this Article Ninth shall be construed to limit or restrict the Board in the exercise of its fiduciary duties under applicable law.

(v)    Notwithstanding the foregoing, the Board shall take no action pursuant to this Article Ninth, including without limitation this section (g) of this Article Ninth, to restrict any sale, disposition, or other transfer of Corporation Securities by the Fire Victim Trust that do not result in Prohibited Transfers and are otherwise permitted under this Article Ninth.

(h)    Reliance. To the fullest extent permitted by law, the Corporation and the members of the Board or any committee thereof shall be fully protected in relying in good faith upon the information, opinions, reports or statements of the chief executive officer, the chief financial officer, the chief accounting officer, the Secretary or the corporate controller of the Corporation or of the Corporation’s legal counsel, independent auditors, transfer agent, investment bankers or other employees and agents in making the determinations and findings contemplated by this Article Ninth, and the members of the Board shall not be responsible for any good faith errors made in connection therewith. For purposes of determining the existence and identity of, and the amount of any Corporation Securities owned by any shareholder, the Corporation is entitled to rely on the existence and absence of filings of Schedule 13D, 13F or 13G under the Securities Exchange Act of 1934, or similar statements, reports or other filings, as of any date, subject to its actual knowledge of the ownership of Corporation Securities.

(i)    Benefits of this Article Ninth. Nothing in this Article Ninth shall be construed to give to any Person other than the Corporation, the Agent and members of the Board and such committee thereof any legal or equitable right, remedy or claim under this Article Ninth. This Article Ninth shall be for the sole and exclusive benefit of the Corporation, the Agent and members of the Board or any such committee thereof.

(j)    Severability. The purpose of this Article Ninth is to facilitate the Company Group’s ability to maintain or preserve its Tax Benefits. If any provision of this Article Ninth or the application of any such provision to any Person or under any circumstance shall be held invalid, illegal or unenforceable in any respect by a court of competent jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision of this Article Ninth.

(k)    Waiver. With regard to any power, remedy or right provided herein or otherwise available to the Corporation or the Agent under this Article Ninth, (i) no waiver will be effective unless expressly contained in a writing signed by the waiving party, and (ii) no alteration, modification or impairment will be implied by reason of any previous waiver, extension of time, delay or omission in exercise, or other indulgence.

TENTH: If any subsidiary of the Corporation is the holder of record of shares of the Corporation’s Common Stock as of the record date for the payment of any dividend of cash or property (other than a dividend of shares of the Corporation) to the holders of the Corporation’s Common Stock, that subsidiary shall not be entitled to receive payment of any such dividend, and the Corporation shall automatically and without any further action be entitled to retain any such dividend that would otherwise be payable to its subsidiary in respect of such shares. For purposes of this Article Tenth, “subsidiary” means a corporation shares of which possessing more than 50 percent of the voting power are owned directly or indirectly through one or more subsidiaries of the Corporation.

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EX-4.62(A)

EXHIBIT 4.62(a)

DESCRIPTION OF PG&E CORPORATION’S SECURITIES REGISTERED UNDER SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

The following description of PG&E Corporation’s common stock (the “Common Stock”) and equity units (each an “Equity Unit”) is only a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to applicable law, our Amended and Restated Articles of Incorporation filed June 22, 2020, as amended by the Certificate of Amendment filed May 24, 2022 (the “Articles of Incorporation”), our Bylaws amended and restated as of June 22, 2020 (the “Bylaws”), the purchase contract agreement (the “purchase contract agreement”), dated as of July 1, 2020 between us and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent (the “purchase contract agent”) and attorney-in-fact for the holders of purchase contracts from time to time and the custodial agreement (the “custodial agreement”), dated as of July 1, 2020 between the purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as the custodian for the holders of the Equity Units (the “custodian”), each of which is filed as an exhibit to this Annual Report on Form 10-K and is incorporated by reference herein. We encourage you to read the Articles of Incorporation, the Bylaws, the purchase contract agreement and the custodial agreement for additional information.

In this section, references to “we,” “our,” “ours” and “us” refer only to PG&E Corporation and not to any of its direct or indirect subsidiaries or affiliates except as expressly provided.

Description of the Common Stock

General

Our Articles of Incorporation authorize the issuance of 3,600,000,000 shares of Common Stock and 400,000,000 shares of preferred stock. As of December 31, 2022, there were approximately 2,465,528,538 shares of our Common Stock, no par value, outstanding and no shares of preferred stock outstanding. All outstanding shares of our Common Stock are fully paid and nonassessable.

We may issue our Common Stock from time to time upon such terms and for such consideration as may be determined by our Board of Directors. Such further issuances, up to the aggregate amounts authorized by our Articles of Incorporation, will not require approval by our shareholders. We may also issue Common Stock from time to time under dividend reinvestment and employee benefit plans.

Voting Rights

Except as otherwise provided by law, holders of our Common Stock have voting rights on the basis of one vote per share on each matter submitted to a vote at a meeting of shareholders, subject to any class or series voting rights of holders of our preferred stock. Our shareholders may not cumulate votes in elections of directors. As a result, the holders of our Common Stock and (if issued) preferred stock entitled to exercise more than 50% of the voting rights in an election of directors can elect all of the directors to be elected if they choose to do so. In such event, the holders of the remaining Common Stock and preferred stock voting for the election of directors will not be able to elect any persons to the Board of Directors.

Dividend Rights

Holders of our Common Stock, subject to any prior rights or preferences of preferred stock outstanding, have equal rights to receive dividends if and when declared by our Board of Directors out of funds legally available therefor, except for dividends of cash or property.

Liquidation Rights

In the event of our liquidation, dissolution or winding up and after payment of all prior claims, holders of our Common Stock would be entitled to receive any of our remaining assets, subject to any preferential rights of holders of outstanding shares of preferred stock.

Conversion, Redemption and Preemptive Rights

Internal

Holders of our Common Stock have no preemptive rights to subscribe for additional shares of Common Stock or any of our other securities, nor do holders of our Common Stock have any redemption or conversion rights.

Listing

Our Common Stock is listed on the New York Stock Exchange under the symbol “PCG.”

Transfer Agent and Registrar

The transfer agent and registrar for our Common Stock is EQ Shareowner Services.

Limitations on Rights of Holders of Common Stock - Preferred Stock

The rights of holders of Common Stock may be materially limited or qualified by the rights of holders of preferred stock that we may issue in the future. Set forth below is a description of PG&E Corporation’s authority to issue preferred stock and the possible terms of that stock.

Our Board of Directors is authorized, pursuant to our Articles of Incorporation, to issue up to 400,000,000 shares of preferred stock in one or more series and to fix and determine the number of shares of preferred stock of any series, to determine the designation of any such series, to increase or decrease the number of shares of any such series subsequent to the issue of shares of that series, and to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any such series.

Prior to the issuance of shares of each series of our preferred stock, our Board of Directors is required to adopt resolutions and file a certificate of determination with the Secretary of State of the State of California. The certificate of determination will fix for each series the designation and number of shares and the rights, preferences, privileges and restrictions of the shares including, but not limited to, the following:

•the title and stated value of the preferred stock;

•voting rights, if any, of the preferred stock;

•any rights and terms of redemption (including sinking fund provisions);

•the dividend rate(s), period(s) and/or payment date(s) or method(s) of calculation applicable to the preferred stock;

•whether dividends are cumulative or non-cumulative and, if cumulative, the date from which dividends on the preferred stock will accumulate;

•the relative ranking and preferences of the preferred stock as to dividend rights and rights upon the liquidation, dissolution or winding up of our affairs;

•the terms and conditions, if applicable, upon which the preferred stock will be convertible into our Common Stock, including the conversion price (or manner of calculation) and conversion period;

•the provision for redemption, if applicable, of the preferred stock;

•the provisions for a sinking fund, if any, for the preferred stock;

•liquidation preferences;

•any limitations on issuance of any class or series of preferred stock ranking senior to or on a parity with the class or series of preferred stock as to dividend rights and rights upon liquidation, dissolution or winding up of our affairs; and

•any other specific terms, preferences, rights, limitations or restrictions of the preferred stock.

All shares of preferred stock will, when issued, be fully paid and nonassessable and will not have any preemptive or similar rights.

In addition to the terms listed above, we will set forth in a prospectus supplement the following terms relating to the class or series of preferred stock being offered:

•the number of shares of preferred stock offered, the liquidation preference per share and the offering price of the preferred stock;

•the procedures for any auction and remarketing, if any, for the preferred stock;

•any listing of the preferred stock on any securities exchange; and

•a discussion of any material and/or special United States federal income tax considerations applicable to the preferred stock.

Until our Board of Directors determines the rights of the holders of a series of preferred stock, we cannot predict the effect of the issuance of any shares of such series of preferred stock upon the rights of holders of our Common Stock. However, the effect could include one or more of the following:

•restricting dividends on our Common Stock;

•diluting the voting power of our Common Stock;

•impairing the liquidation rights of our Common Stock; or

•delaying or preventing a change in control of us without further action by our shareholders.

Our preferred stock, if issued, would rank, with respect to dividends and upon our liquidation, dissolution or winding up:

•senior to all classes or series of our Common Stock and to all of our equity securities ranking junior to the preferred stock;

•on a parity with all of our equity securities the terms of which specifically provide that the equity securities rank on a parity with the preferred stock; and

•junior to all of our equity securities the terms of which specifically provide that the equity securities rank senior to the preferred stock.

Holding Company Structure

PG&E Corporation conducts its operations primarily through its subsidiaries and substantially all of its consolidated assets are held by its subsidiaries, including Pacific Gas and Electric Company (the “Utility”). Accordingly, PG&E Corporation’s cash flow and its ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the distribution or other payment of these earnings to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances. PG&E Corporation’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts or make any funds available for payment pursuant to PG&E Corporation’s obligations.

Because PG&E Corporation is a holding company, its obligations will be structurally subordinated to all existing and future liabilities of its subsidiaries, including all debt securities and issued and outstanding preferred stock of the Utility (see Exhibit 4.60(b)) for a description of such preferred stock). Furthermore, the rights of PG&E Corporation to participate in the assets of any subsidiary upon the liquidation or reorganization of the subsidiary will be subject to the prior claims of such subsidiary’s creditors, including any holders of preferred stock of such subsidiary. To the extent that PG&E Corporation is itself a creditor with recognized claims against any of its subsidiaries, its claims would still be effectively subordinated to any security interest in, or mortgages or other liens on, the assets of the subsidiary and would be subordinated to any indebtedness or other liabilities of the subsidiary that are senior to the claims held by PG&E Corporation.

Description of the Equity Units

In July and August 2020, we issued 16,000,000 Equity Units, each with a stated amount of $100. Each Equity Unit is comprised of (i) a prepaid forward stock purchase contract (a “purchase contract”) of PG&E Corporation and (ii) a 1/48,000th undivided beneficial ownership interest in specified U.S. treasury strips that mature on a quarterly basis from, and including, August 15, 2020 through, and including, August 15, 2023 and are held by the custodian as agent for the holders of the Equity Units (a “U.S. treasury strips component”). The following summary of the terms of the Equity Units, the summary of the terms of the purchase contracts set forth under the caption “Description of the Purchase Contracts” and the summary of the terms of the U.S. treasury strips components set forth under the caption “Description of the U.S. Treasury Strips Components” below contain a description of all of the material terms of the Equity Units and their components but are not complete and are subject to, and qualified in their entirety by reference to, the related contracts. We refer you to the purchase contract agreement and the custodial agreement, which are incorporated by reference to this Annual Report on Form 10-K.

Components of the Equity Units

Each Equity Unit is comprised of:

• a prepaid forward stock purchase contract of PG&E Corporation entitling the holder to receive a number of shares of our Common Stock on August 16, 2023 (subject to postponement in certain limited circumstances, the “purchase contract settlement date”), or earlier if a “fundamental change” occurs prior to the settlement date or if the holder has elected “early settlement” (in each case, as defined herein and described below), determined by reference to the settlement rate described below; and

• a U.S. treasury strips component.

Unless previously settled at the holder’s option as described in “Description of the Purchase Contracts-Early Settlement” or “Description of the Purchase Contracts-Early Settlement Upon a Fundamental Change,” we will deliver to the holder, on the purchase contract settlement date, in respect of each purchase contract not more than 10.5263 shares of our Common Stock and not less than 8.5929 shares of our Common Stock, based upon the applicable “settlement rate” (as defined below), which is subject to adjustment as described herein, and the “applicable market value” (as defined below) of our Common Stock, as described below under “Description of the Purchase Contracts-Delivery of Common Stock.”

Each holder of Equity Units will be paid the amount received by the custodian from the U.S. government in respect of each U.S. treasury strip underlying the Equity Units owned by such holder on the business day immediately following the date such U.S. treasury strip matures on February 15, May 15, August 15 and November 15 of each year, with such payments commencing on, and including, August 17, 2020, and ending on, and including, August 16, 2023, as described below under “Description of the U.S. Treasury Strips Components.”

The stated amount of each Equity Unit must be allocated between the U.S. treasury strips component and the purchase contract based upon their relative fair market values. We have determined that the fair market value of each U.S. treasury strips component is $17.1402 and the fair market value of each purchase contract is $82.8574. Each holder agrees to such allocation and this position is binding upon each holder (but not on the Internal Revenue Service).

Separating and Recreating Equity Units

Upon the conditions and under the circumstances described below, a holder of 48,000 Equity Units (or any integral multiple thereof) has the right to separate its Equity Units into its component parts, and a holder of 48,000 separate purchase contracts (or any integral multiple thereof) and the underlying U.S. treasury strips has the right to combine these components to recreate 48,000 Equity Units (or any integral multiple thereof).

Separating Equity Units

At initial issuance, the purchase contracts and U.S. treasury strips components may be purchased and transferred only as Equity Units and will trade under the CUSIP number for the Equity Units.

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 Equity Units (or any integral multiple thereof) will have the right to separate such Equity Units and withdraw the U.S. treasury strips underlying those Equity Units. Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any separation of Equity Units may be made only in integral multiples of 48,000 Equity Units. To withdraw the U.S. treasury strips evidenced by the Equity Units, the holder must:

• deliver the relevant Equity Units to the purchase contract agent; and

• deliver a notice to the purchase contract agent requesting that the purchase contract agent instruct the custodian to release to the holder the U.S. treasury strips underlying those Equity Units.

The purchase contract agent will then (i) cancel the Equity Units and deliver to the holder the purchase contracts underlying those Equity Units, which we refer to as “separate purchase contracts” and (ii) instruct the custodian to deliver to the holder the underlying U.S. treasury strips. If the holder has withdrawn the U.S. treasury strips previously underlying an Equity Unit, it may either continue to hold the separate purchase contract in global form through the purchase contract agent or receive a certificate for its separate purchase contract and hold it directly as the owner registered on the purchase contract register maintained on our behalf by the purchase contract registrar. Any administrative fees and expenses related to withdrawing the U.S. treasury strips evidenced by the Equity Units that are payable to the purchase contract agent or the custodian will be at the expense of the holder of Equity Units requesting withdrawal.

“Business day”means any day other than a Saturday, Sunday or any day on which banking institutions in New York, New York are authorized or obligated by applicable law or executive order to close or be closed.

There is no current or expected trading market for the separate purchase contracts and we do not intend to apply to have the separate purchase contracts listed on any securities exchange or quoted on any automated quotation system. Accordingly, we do not expect there to be a liquid market in the separate purchase contracts at any time. Separate purchase contracts and the withdrawn U.S. treasury strips will be transferable independently from each other.

Recreating Equity Units

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 separate purchase contracts (or any integral multiple thereof) will have the right to recreate Equity Units by delivering, for every 48,000 Equity Units being recreated, (i) to the purchase contract agent, 48,000 separate purchase contracts, and (ii) to the custodian, $66,000 face amount (or $33,000 face amount in the case of the U.S. treasury strips maturing on August 15, 2020) of each of the U.S. treasury strips that would be then remaining as a portion of the U.S. treasury strips component of an Equity Unit. Any recreation of Equity Units may be made only in integral multiples of 48,000 Equity Units. The newly deposited U.S. treasury strips used to recreate the Equity Units must have the same CUSIP numbers as the ones originally comprising the U.S. treasury strips component.

Global Securities

Each Equity Unit and purchase contract are represented by global securities registered in the name of a nominee of The Depository Trust Company (“DTC”). Holders are not entitled to receive definitive physical certificates for the Equity Units and purchase contracts, except under the limited circumstances described under “Book-Entry Procedures and Settlement.” Beneficial interests in an Equity Unit and, after separation, the separate purchase contract, will be represented through book-entry accounts of, and transfers will be effected through, direct or indirect participants in DTC.

Deemed Actions by Holders by Acceptance

Each holder of Equity Units or separate purchase contracts, by acceptance of such securities, is deemed to have:

• irrevocably authorized and directed the purchase contract agent to execute, deliver and perform on its behalf the purchase contract agreement, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes;

• in the case of a purchase contract that is a component of an Equity Unit, or that is evidenced by a separate purchase contract, irrevocably authorized and directed the purchase contract agent to execute, deliver and hold on its behalf the separate purchase contract or the component purchase contract evidencing such purchase contract, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes;

• consented to, and agreed to be bound by, the terms and provisions of the purchase contract agreement;

• in the case of a holder of an Equity Unit, agreed, for all purposes, including U.S. federal income tax purposes, to treat:

• an Equity Unit as an investment unit composed of two separate instruments, in accordance with its form;

• the allocation of the stated amount per Equity Unit between the purchase contract and the U.S. treasury strips component so that such holder’s initial tax basis in each purchase contract will be $82.8574 and such holder’s initial tax basis in each U.S. treasury strips component will be $17.1402;

• represented and warranted that neither the beneficial holder of the purchase contracts (including for these purposes a purchase contract that is a component of any Equity Unit) nor, to the knowledge of such beneficial holder, any other person, would become a “Substantial Shareholder” (as defined in the Amended Articles) as a result of such beneficial holder’s acquisition of purchase contracts (treating the beneficial holder and any such other person as actually holding, solely for purposes of this representation, the number of shares of our Common Stock that would be received upon settlement at the maximum settlement rate of all purchase contracts acquired or beneficially owned by such beneficial holder or any such other person, as applicable, but treating all other purchase contracts as still unsettled), and, for the avoidance of doubt, taking into account such beneficial holder’s and any such other person’s (i) current ownership of our Common Stock and any of the Utility’s preferred stock and (ii) other acquisitions of our Common Stock and any of the Utility’s preferred stock (if any) concurrent with or in connection with such beneficial holder’s acquisition of purchase contracts; and

• appointed the custodian to hold on its behalf and to receive payments related to the U.S. treasury strips components and agreed to indemnify the custodian from and against any liability it may incur in connection with such appointment in the absence of gross negligence or willful misconduct on its part.

Listing of Securities

Our Equity Units are listed on the NYSE under the symbol “PCGU.” However, listing on the NYSE does not guarantee that a trading market will develop, and the underwriters may discontinue market making at any time in their sole discretion without prior notice to Equity Unit holders. Accordingly, there can be no assurance that a liquid trading market will develop for the Equity Units (or, if developed, that a liquid trading market will be maintained), that the holder will be able to sell Equity Units at a particular time or that the prices the holder receives when the holder sells will be favorable.

Title

The purchase contract agent may treat the registered owner of any Equity Unit, which at initial issuance was a nominee of DTC, or, upon withdrawal of the U.S. treasury strips, the registered owner of any separate purchase contract, as the absolute owner thereof for the purpose of making payment and settling the purchase contracts and

for all other purposes. Similarly, the custodian may treat the registered owner of any Equity Unit as the absolute owner thereof for the purpose of making payments of the U.S. treasury strips components and deliveries of the underlying U.S. treasury strips, if applicable, and for all other purposes.

Accounting for the Equity Units

We record the issuance of the purchase contract portion of the Equity Units as Common Stock, net of issuance costs of the purchase contracts, in our financial statements. All of the proceeds from the issuance of the U.S. treasury strips components were paid to the custodian, and we did not receive any proceeds from such issuance.

Based on U.S. GAAP, we do not expect the purchase contract component of the Equity Units to be revalued under fair value accounting principles.

Our earnings per share calculations will reflect the shares issuable upon settlement of the purchase contracts portion of the Equity Units. Our basic earnings per share will include the minimum shares issuable under the purchase contract for each period and our diluted earnings per share will include any incremental shares that would be issuable assuming a settlement of the purchase contract at the end of each accounting period, if dilutive.

Replacement of Equity Unit Certificates

In the event that physical certificates evidencing the Equity Units have been issued, any mutilated equity unit certificate will be replaced by us at the expense of the holder upon surrender of the certificate to the purchase contract agent. Equity Unit certificates that have been destroyed, lost or stolen will be replaced by us at the expense of the holder upon delivery to us and the purchase contract agent of evidence of their destruction, loss or theft satisfactory to us and the purchase contract agent. In the case of a destroyed, lost or stolen Equity Unit certificate, an indemnity satisfactory to us and the purchase contract agent may be required at the expense of the holder of the Equity Units before a replacement will be issued.

Notwithstanding the foregoing, we will not be obligated to replace any Equity Unit certificates on or after the second scheduled trading day immediately preceding August 16, 2023 or any early settlement date. In those circumstances, the purchase contract agreement will provide that, in lieu of the delivery of a replacement Equity Unit certificate, the purchase contract agent, upon delivery of the evidence and indemnity described above, will deliver or arrange for delivery of the shares of Common Stock issuable pursuant to the purchase contracts included in the Equity Units evidenced by the Equity Unit certificate.

Miscellaneous

The purchase contract agreement provides that we will pay all fees and expenses related to the offering of the Equity Units and the enforcement by the purchase contract agent of the rights of the holders of the Equity Units or the separate purchase contracts, other than expenses (including legal fees) of the underwriters.

Should the holder elect to separate or recreate Equity Units, the holder will be responsible for any fees or expenses payable in connection with that separation or recreation, and we will have no liability therefor.

Description of the Purchase Contracts

The purchase contracts are issued pursuant to the terms and provisions of the purchase contract agreement. The following summary contains a description of all of the material terms of the purchase contracts but is not complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the purchase contract agreement, including the definitions in the purchase contract agreement of certain terms. We refer you to the purchase contract agreement which is incorporated by reference to this Annual Report on Form 10-K.

Each purchase contract will initially form a part of an Equity Unit. On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, the holder will have the right to separate 48,000 Equity Units (or any integral multiple thereof) and withdraw the U.S. treasury strips underlying those Equity Units. Following such separation, purchase contracts may be transferred separately from the U.S. treasury strips components.

Delivery of Common Stock

Unless settled early at the holder’s option, for each purchase contract we will deliver to the holder on August 16, 2023 (subject to postponement in certain limited circumstances described below, the “purchase contract settlement date”), a number of shares of our Common Stock. The number of shares of our Common Stock issuable upon settlement of each purchase contract (the “settlement rate”) will be determined by us as follows:

• if the applicable market value of our Common Stock is greater than the threshold appreciation price, then the holder will receive 8.5929 shares of Common Stock for each purchase contract (the “minimum settlement rate”);

• if the applicable market value of our Common Stock is greater than or equal to the reference price but less than or equal to the threshold appreciation price, then the holder will receive a number of shares of Common Stock for each purchase contract equal to the Equity Unit stated amount of $100, divided by the applicable market value; and

• if the applicable market value of our Common Stock is less than the reference price, then the holder will receive 10.5263 shares of Common Stock for each purchase contract (the “maximum settlement rate”).

The maximum settlement rate and minimum settlement rate are each subject to adjustment as described under “-Anti-Dilution Adjustments to the Fixed Settlement Rates” below. Each of the minimum settlement rate and the maximum settlement rate is referred to as a “fixed settlement rate.”

The reference price is equal to $100 divided by the maximum settlement rate and is approximately equal to $9.5000.

The threshold appreciation price is equal to $100 divided by the minimum settlement rate. The threshold appreciation price, which is initially approximately $11.6375, represents an appreciation of approximately 22.50% over the reference price.

For illustrative purposes only, the following table shows the number of shares of Common Stock issuable upon settlement of a purchase contract at assumed applicable market values, based on a reference price of $9.5000 and a threshold appreciation price of $11.6375. The table assumes that there will be no adjustments to the fixed settlement rates described below under “-Anti-Dilution Adjustments to the Fixed Settlement Rates” below or settled early at the option of holders as described under “-Early Settlement” or “-Early Settlement Upon a Fundamental Change” below. There can be no assurance that the actual applicable market value will be within the assumed range set forth below.

A holder of an Equity Unit or a separate purchase contract, as applicable, would receive on the purchase contract settlement date the following numbers of shares of Common Stock for each Equity Unit or separate purchase contract at the following assumed applicable market values:

Assumed Applicable Market Value	Number of Shares of Common Stock
$2.00		10.5263
$4.00		10.5263
$6.00		10.5263
$8.00		10.5263
$9.50		10.5263
$10.50		9.5238
$11.64		8.5929
$13.00		8.5929
$15.00		8.5929
$18.00		8.5929
$21.00		8.5929
$25.00		8.5929
$30.00		8.5929
$35.00		8.5929

As the above table illustrates, if, on the purchase contract settlement date, the applicable market value is greater than the threshold appreciation price, we would be obligated to deliver 8.5929 shares of Common Stock for each purchase contract.

If, on the purchase contract settlement date, the applicable market value is less than or equal to the threshold appreciation price but greater than or equal to the reference price of approximately $9.5000, we would be obligated to deliver a number of shares of our Common Stock on the purchase contract settlement date equal to $100, divided by the applicable market value. As a result, we would retain all appreciation in the market value of our Common Stock underlying each purchase contract between the reference price and the threshold appreciation price.

If, on the purchase contract settlement date, the applicable market value is less than the reference price of approximately $9.5000, we would be obligated to deliver upon settlement of the purchase contract 10.5263 shares of Common Stock for each purchase contract, regardless of the market price of our Common Stock. As a result, the holder would suffer the full decline in market value of the Common Stock below the reference price.

Because the applicable market value of the Common Stock is determined over the “valuation period” (as defined below), the number of shares of Common Stock delivered for each purchase contract may be greater than or less than the number that would have been delivered based on the closing price (or daily VWAP) of the Common Stock on the last trading day of such valuation period. In addition, the holder will bear the risk of fluctuations in the market price of the shares of Common Stock deliverable upon settlement of the purchase contracts between the end of such valuation period and the date such shares are delivered.

The term “applicable market value” means the arithmetic average of the daily VWAPs of our Common Stock on each trading day of the valuation period.

The term “valuation period” means each of the 20 consecutive trading days beginning on, and including, the 21st scheduled trading day immediately preceding August 16, 2023.

The “daily VWAP” of our Common Stock on any trading day means the per share volume-weighted average price as displayed under the heading “Bloomberg VWAP” on Bloomberg page “PCG <equity> AQR” (or its equivalent successor if such page is not available) in respect of the period from the scheduled open of trading until the scheduled close of trading of the primary trading session on such trading day (or if such volume-weighted average price is unavailable, the market value of one share of our Common Stock on such trading day determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by us). The “daily VWAP” will be determined without regard to after-hours trading or any other trading outside of the regular trading session trading hours. The “average VWAP” per share over a certain period means the arithmetic average of the daily VWAP per share for each trading day in such period.

“Trading day” means a day on which (i) there is no “market disruption event” (as defined below) and (ii) trading in our Common Stock (or other security for which a daily VWAP must be determined) generally occurs on the NYSE or, if our Common Stock (or such other security) is not then listed on the NYSE, on the principal other U.S. national or regional securities exchange on which our Common Stock (or such other security) is then listed or, if our Common Stock (or such other security) is not then listed on a U.S. national or regional securities exchange, on the principal other market on which our Common Stock (or such other security) is then traded. If our Common Stock (or such other security) is not so listed or traded, “trading day” means a “business day.”

“Scheduled trading day” means a day that is scheduled to be a trading day on the NYSE or, if our Common Stock is not then listed on the NYSE, on the principal other U.S. national or regional securities exchange on which our Common Stock is then listed or, if our Common Stock is not then listed on a U.S. national or regional securities exchange, on the principal other market on which our Common Stock is then traded. If our Common Stock is not so listed or admitted for trading, “scheduled trading day” means a “business day.”

“Market disruption event” means (i) a failure by the primary U.S. national or regional securities exchange or market on which our Common Stock is listed or admitted for trading to open for trading during its regular trading session or (ii) the occurrence or existence prior to 1:00 p.m., New York City time, on any scheduled trading day for our Common Stock for more than one half-hour period in the aggregate during regular trading hours of any suspension or limitation imposed on trading (by reason of movements in price exceeding limits permitted by the relevant stock exchange, relevant market or otherwise) in our Common Stock or in any options contracts or futures contracts relating to our Common Stock.

On the purchase contract settlement date, our Common Stock will be issued and delivered to the holder or the holder’s designee, upon (i) surrender of certificates representing the purchase contracts, if such purchase contracts are held in certificated form, and (ii) payment by the holder of any transfer or similar taxes payable in connection with the issuance of our Common Stock to any person other than the holder. As long as the purchase contracts are evidenced by one or more global purchase contract certificates deposited with DTC, procedures for settlement will be governed by DTC’s applicable procedures.

If one or more of the 20 consecutive scheduled trading days in the valuation period is not a trading day, the purchase contract settlement date will be postponed until the second business day immediately following the last trading day of the valuation period.

Prior to 5:00 p.m., New York City time, on the last trading day of the valuation period, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock shall be issuable upon settlement of the purchase contract on the purchase contract settlement date will be treated as the holder of record of such shares as of 5:00 p.m., New York City time, on the last trading day of the 20 consecutive trading day period during which the applicable market value is determined.

We will pay any documentary, stamp or similar issue or transfer tax due on the issue of any shares of our Common Stock upon settlement of the purchase contracts, unless the tax is due because the holder requests any shares to be issued in a name other than the holder’s name, in which case the holder will pay that tax.

Early Settlement

Prior to 5:00 p.m., New York City time on the second scheduled trading day immediately preceding August 16, 2023, any holder of 48,000 Equity Units (or any integral multiple thereof) or a holder of one or more separate purchase contracts, may elect to settle such Equity Units or separate purchase contracts early and receive a number of shares of Common Stock per purchase contract equal to the “early settlement rate.” The early settlement rate is equal to the minimum settlement rate on the early settlement date, subject to adjustment as described below under “-Anti-Dilution Adjustments to the Fixed Settlement Rates,” unless the holder elects to settle the holder’s purchase contracts early in connection with a fundamental change, in which case the holder will receive upon settlement of the holder’s purchase contracts a number of shares of our Common Stock based on the “fundamental change early settlement rate” as described under “-Early Settlement Upon a Fundamental Change.” We refer to this right as the “early settlement right.”

The holder’s right to receive Common Stock upon early settlement of a purchase contract is subject to (i) delivery of a written and signed notice of election (an “early settlement notice”) to the purchase contract agent electing early settlement of such purchase contract, (ii) if such purchase contract or the Equity Unit that includes such purchase contract is held in certificated form, surrendering the certificates representing the purchase contract and (iii) payment

by the holder of any transfer or similar taxes payable in connection with the issuance of our Common Stock to any person other than the holder. As long as the purchase contracts or the Equity Units are evidenced by one or more global certificates deposited with DTC, procedures for early settlement will be governed by DTC’s applicable procedures.

Upon surrender of the Equity Unit or the separate purchase contract, as applicable, and payment of any applicable transfer or similar taxes due because of any issue of such shares in a name of a person other than the holder, the holder will receive the applicable number of shares of Common Stock (and any cash payable for fractional shares) due upon early settlement on the second business day following the “early settlement date” (as defined below).

If the holder complies with the requirements for effecting the early settlement right prior to 5:00 p.m., New York City time, on any business day, then that day will be considered the “early settlement date.” If the holder complies with such requirements at or after 5:00 p.m., New York City time, on any business day or at any time on a day that is not a business day, then the next succeeding business day will be considered the “early settlement date.” Prior to 5:00 p.m., New York City time, on the early settlement date, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock shall be issuable upon such early settlement of the purchase contract will be treated as the holder of record of such shares as of 5:00 p.m., New York City time, on the relevant early settlement date.

Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any early settlement of Equity Units may be made only in integral multiples of 48,000 Equity Units.

Upon early settlement at the holder’s election of purchase contracts held as components of Equity Units, the custodian will deliver the U.S. treasury strips evidenced by those Equity Units to such holder free and clear of any liens or other encumbrances on the second business day following the early settlement date.

Early Settlement Upon a Fundamental Change

If a “fundamental change” occurs and the holder elects to settle the holder’s purchase contracts early in connection with such fundamental change in accordance with the procedures described under “-Early Settlement” above, the holder will receive per purchase contract a number of shares of our Common Stock or cash, securities or other property, as applicable, equal to the “fundamental change early settlement rate,” as described below. An early settlement will be deemed for these purposes to be “in connection with” such fundamental change if the holder delivers the holder’s early settlement notice to the purchase contract agent, and otherwise satisfies the requirements for effecting early settlement of the holder’s purchase contracts, during the period beginning on, and including, the effective date of the fundamental change and ending at 5:00 p.m., New York City time, on the 35th business day thereafter (or, if earlier, the second scheduled trading day immediately preceding August 16, 2023) (the “fundamental change early settlement period”). We refer to this right as the “fundamental change early settlement right.”

If the holder complies with the requirements for effecting the fundamental change early settlement right prior to 5:00 p.m., New York City time, on any business day during the fundamental change early settlement period, then that day will be considered the “fundamental change early settlement date.” If the holder complies with such requirements at or after 5:00 p.m., New York City time, on any business day during the fundamental change early settlement period or at any time on a day during the fundamental change early settlement period that is not a business day, then the next succeeding business day will be considered the “fundamental change early settlement date.”

Any early settlement of Equity Units in connection with a fundamental change may be made only in integral multiples of 48,000 Equity Units.

We will provide the purchase contract agent, custodian and the holders of Equity Units and separate purchase contracts with a notice of a fundamental change within five business days after its effective date and issue a press release announcing such effective date. The notice will also set forth, among other things, (i) the applicable fundamental change early settlement rate, (ii) if not Common Stock, the kind and amount of cash, securities and other property receivable by the holder upon settlement and (iii) the deadline by which each holder’s fundamental change early settlement right must be exercised.

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

• any “person” or “group” within the meaning of Section 13(d) of the Exchange Act of 1934, as amended (the “Exchange Act”), other than us, any of our wholly owned subsidiaries and any of our and their employee benefit plans, files a Schedule TO or any other schedule, form or report under the Exchange Act disclosing that such person or group has become the direct or indirect “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the outstanding shares of our Common Stock;

• the consummation of (A) any recapitalization, reclassification or change of our Common Stock (other than changes resulting from a subdivision or combination) as a result of which our Common Stock would be converted into, or exchanged for, stock, other securities, other property or assets; (B) any share exchange, consolidation or merger of us pursuant to which our Common Stock will be converted into cash, securities or other property or assets; or (C) any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of us and our subsidiaries, taken as a whole, to any person other than one of our wholly owned subsidiaries; or

• our Common Stock (or other Common Stock receivable upon settlement of the holder’s purchase contracts, if applicable) ceases to be listed or quoted on any of the NYSE, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors).

A transaction or transactions described in either of the first two bullets above will not constitute a fundamental change, however, if (i) at least 90% of the consideration received or to be received by stockholders of our Common Stock (excluding cash payments for fractional shares) in connection with such transaction or transactions consists of shares of Common Stock that are listed on any of the NYSE, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors), or will be so listed when issued or exchanged in connection with such transaction or transactions and (ii) as a result of such transaction or transactions such consideration becomes the consideration receivable upon settlement of the holder’s purchase contracts, if applicable, excluding cash payments for fractional shares.

If any transaction in which our Common Stock is replaced by the securities of another entity occurs, following completion of any related fundamental change early settlement period (or, in the case of a transaction that would have been a fundamental change but for the immediately preceding paragraph, following the effective date of such transaction), references to us in the definition of “fundamental change” above shall instead be references to such other entity.

The “fundamental change early settlement rate” will be determined by us by reference to the table below, based on the date on which the fundamental change occurs or becomes effective (the “fundamental change effective date”) and the “stock price” in the fundamental change, which will be:

• in the case of a fundamental change described in the second bullet of the definition of “fundamental change” in which all holders of shares of our Common Stock receive only cash in the fundamental change, the stock price will be the cash amount paid per share of our Common Stock; and

• in all other cases, the stock price will be the arithmetic average of the daily VWAPs of our Common Stock over the five consecutive trading day period ending on the trading day immediately preceding such fundamental change effective date.

The stock prices set forth in the column headings of the table below will be adjusted as of any date on which the fixed settlement rates are adjusted. The adjusted stock prices will equal the stock prices applicable immediately prior to such adjustment, multiplied by a fraction, the numerator of which is the maximum settlement rate immediately prior to the adjustment giving rise to the stock price adjustment and the denominator of which is the maximum settlement rate as so adjusted. The fundamental change early settlement rates per purchase contract in the table below will be adjusted in the same manner and at the same time as the fixed settlement rates as set forth under “-Anti-Dilution Adjustments to the Fixed Settlement Rates.”

The following table sets forth the fundamental change early settlement rate per purchase contract for each stock price and fundamental change effective date set forth below:

Stock Price
Fundamental Change Effective Date	$    2.00	$    4.00	$    6.00	$    8.00	$    9.50	$    10.50	$    11.64	$    13.00	$    15.00	$    18.00
July 1, 2020	10.3248	9.9939	9.5052	9.0924	8.8699	8.7592	8.663	8.5811	8.5065	8.4547
August 16, 2020	10.3372	10.0252	9.5399	9.12	8.8914	8.7774	8.6781	8.5936	8.5167	8.4633
February 16, 2021	10.3813	10.1499	9.6883	9.2397	8.9836	8.8538	8.7404	8.6438	8.5564	8.4966
August 16, 2021	10.417	10.2681	9.852	9.3763	9.0862	8.9361	8.8043	8.6924	8.5927	8.5265
February 16, 2022	10.4472	10.3753	10.0399	9.5445	9.2088	9.0297	8.8715	8.7386	8.6236	8.5521
August 16, 2022	10.4738	10.4551	10.2454	9.7595	9.3615	9.137	8.9374	8.7734	8.6408	8.5695
February 16, 2023	10.5002	10.4998	10.4479	10.0823	9.5949	9.276	8.9882	8.7694	8.6265	8.5775
August 16, 2023	10.5263	10.5263	10.5263	10.5263	10.5263	9.5238	8.5929	8.5929	8.5929	8.5929

The exact stock prices and fundamental change effective dates may not be set forth in the table above, in which case:

• if the applicable stock price is between two stock prices in the table or the applicable fundamental change effective date is between two fundamental change effective dates in the table, the fundamental change early settlement rate will be determined by straight line interpolation between the fundamental change early settlement rates set forth for the higher and lower stock prices and the earlier and later fundamental change effective dates, as applicable, based on a 365- or 366-day year, as applicable;

• if the applicable stock price is greater than $35.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above), then the fundamental change early settlement rate will be the minimum settlement rate; or

• if the applicable stock price is less than $2.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above, the “minimum stock price”), the fundamental change early settlement rate will be determined as if the stock price equaled the minimum stock price, and using straight line interpolation, as described in the first bullet of this paragraph, if the fundamental change effective date is between two fundamental change effective dates in the table.

The maximum number of shares of our Common Stock deliverable under a purchase contract is 10.5263, subject to adjustment in the same manner and at the same time as the fixed settlement rates as set forth under “-Anti-Dilution Adjustments to the Fixed Settlement Rates.”

Our obligation to settle the purchase contracts at the fundamental change early settlement rate could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness of economic remedies.

We will deliver the shares of our Common Stock, securities, cash or other property payable as a result of the holder’s exercise of the fundamental change early settlement right on the second business day following the fundamental change early settlement date. Prior to 5:00 p.m., New York City time, on the fundamental change early settlement date, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock or other securities, if applicable, shall be issuable following exercise of a holder’s

fundamental change early settlement right will be treated as the holder of record of such shares or other securities, if applicable, as of 5:00 p.m., New York City time, on the fundamental change early settlement date.

Upon early settlement of purchase contracts held as components of Equity Units at the holder’s election upon a fundamental change, the custodian will deliver the U.S. treasury strips evidenced by those Equity Units to such holder free and clear of any liens or other encumbrances on the second business day following the fundamental change early settlement date.

If the holder does not elect to exercise the holder’s fundamental change early settlement right, the holder’s purchase contracts will remain outstanding and will be subject to normal settlement on any subsequent early settlement date or any subsequent fundamental change early settlement date, as the case may be.

Anti-Dilution Adjustments to the Fixed Settlement Rates

Each fixed settlement rate will be adjusted as described below, except that we will not make any adjustments to the fixed settlement rates if holders of the purchase contracts participate (other than in the case of a share split or share combination or a tender or exchange offer described in clause (5) below), at the same time and upon the same terms as holders of our Common Stock and solely as a result of holding the purchase contracts, in any of the transactions described below without having to settle their purchase contracts as if they held a number of shares of Common Stock equal to (i) the maximum settlement rate as of the record date for such transaction, multiplied by (ii) the number of purchase contracts held by such holder.

(1) If we exclusively issue shares of our Common Stock as a dividend or distribution on shares of our Common Stock, or if we effect a share split or share combination, each fixed settlement rate will be adjusted based on the following formula:

CR1 = CR0 x	OS1
	OS0

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date (as defined below) of such dividend or distribution, or immediately prior to the open of business on the effective date of such share split or share combination, as applicable;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date or immediately after the open of business on such effective date, as applicable;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date or immediately prior to the open of business on such effective date, as applicable, before giving effect to such dividend, distribution, share split or share combination; and
OS1	=	the number of shares of our Common Stock outstanding immediately after giving effect to such dividend, distribution, share split or share combination.

Any adjustment made under this clause (1) shall become effective immediately after the close of business on the record date for such dividend or distribution, or immediately after the open of business on the effective date for such share split or share combination, as applicable. If any dividend or distribution of the type described in this clause (1) is declared but not so paid or made, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to pay such dividend or distribution, to such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared. For the purposes of this clause (1), the number of shares of our Common Stock outstanding immediately prior to the close of business on the relevant record date or immediately prior to the open of business on the relevant effective date, as the case

may be, and the number of shares of our Common Stock outstanding immediately after giving effect to such dividend, distribution, share split or share combination shall, in each case, not include shares that we hold in treasury. We will not pay any dividend or make any distribution on shares of our Common Stock that we hold in treasury.

“Effective date” as used in this clause (1) means the first date on which the shares of our Common Stock trade on the relevant stock exchange, regular way, reflecting the relevant share split or share combination, as applicable.

“Record date” means, with respect to any dividend, distribution or other transaction or event in which the holders of our Common Stock (or other applicable security) have the right to receive any cash, securities or other property or in which our Common Stock (or such other security) is exchanged for or converted into any combination of cash, securities or other property, the date fixed for determination of holders of our Common Stock (or such other security) entitled to receive such cash, securities or other property (whether such date is fixed by our board of directors or a duly authorized committee thereof, statute, contract or otherwise).

(2) If we issue to all or substantially all holders of our Common Stock any rights, options or warrants entitling them, for a period of not more than 45 calendar days after the announcement date of such issuance, to subscribe for or purchase shares of our Common Stock at a price per share that is less than the average VWAP per share of our Common Stock for the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of such issuance, each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	OS0 + X
	OS0 + Y

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such issuance;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date;
X	=	the total number of shares of our Common Stock issuable pursuant to such rights, options or warrants; and
Y	=	the number of shares of our Common Stock equal to (i) the aggregate price payable to exercise such rights, options or warrants, divided by (ii) the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of the issuance of such rights, options or warrants.

Any increase made under this clause (2) will be made successively whenever any such rights, options or warrants are issued and shall become effective immediately after the close of business on the record date for such issuance. To the extent that such rights, options or warrants are not exercised prior to their expiration or shares of Common Stock are not delivered after the exercise of such rights, options or warrants, each fixed settlement rate shall be decreased to such fixed settlement rate that would then be in effect had the increase with respect to the issuance of such rights, options or warrants been made on the basis of delivery of only the number of shares of Common Stock actually delivered, if any. If such rights, options or warrants are not so issued, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to issue

such rights, options or warrants to such fixed settlement rate that would then be in effect if such record date for such issuance had not occurred.

For the purpose of this clause (2), in determining whether any rights, options or warrants entitle the holders of our Common Stock to subscribe for or purchase shares of our Common Stock at less than such average VWAP per share for the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of such issuance, and in determining the aggregate offering price of such shares of our Common Stock, there shall be taken into account any consideration received by us for such rights, options or warrants and any amount payable on exercise or conversion thereof, the value of such consideration, if other than cash, to be determined by our board of directors in good faith.

(3) If we distribute shares of our capital stock, evidences of our indebtedness, other assets or property of ours or rights, options or warrants to acquire our capital stock or other securities, to all or substantially all holders of our Common Stock, excluding:

• dividends, distributions or issuances as to which the provisions set forth in clause (1) or (2) shall apply;

• dividends or distributions paid exclusively in cash as to which the provisions set forth in clause (4) below shall apply;

• any distributions upon conversion of, or in exchange for, our Common Stock in connection with a recapitalization, reclassification, change, consolidation, merger or other combination, share exchange, or sale, lease or other transfer or disposition resulting in the change in the consideration due upon settlement of the purchase contracts as described below under “-Recapitalizations, Reclassifications and Changes of Our Common Stock”;

• except as otherwise described below, rights issued pursuant to a shareholder rights plan adopted by us; and

• spin-offs as to which the provisions set forth below in this clause (3) shall apply;

then each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	SP0
	SP0 - FMV

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such distribution;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date;
SP0	=	the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the ex-date (as defined below) for such distribution; and
FMV	=	the fair market value (as determined by our board of directors in good faith) of the shares of capital stock, evidences of indebtedness, assets, property, rights, options or warrants so distributed, expressed as an amount per share of our Common Stock on the ex-date for such distribution.

“Ex-date” means the first date on which the shares of our Common Stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive the issuance, dividend or distribution in question, from us or, if applicable, from the seller of our Common Stock on such exchange or market (in the form of due bills or otherwise) as determined by such exchange or market.

Any increase made under the portion of this clause (3) above will become effective immediately after the close of business on the record date for such distribution. If such distribution is not so paid or made, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such distribution had not been declared.

Notwithstanding the foregoing, if “FMV” (as defined above) is equal to or greater than “SP0” (as defined above), in lieu of the foregoing increase, each holder shall receive, in respect of each purchase contract, at the same time and upon the same terms as holders of our Common Stock, without having to settle such purchase contract, the amount and kind of our capital stock, evidences of our indebtedness, other assets or property of ours or rights, options or warrants to acquire our capital stock or other securities that such holder would have received if such holder owned a number of shares of Common Stock equal to the maximum settlement rate in effect on the record date for the distribution.

If we issue rights, options or warrants that are only exercisable upon the occurrence of certain triggering events, then:

• we will not adjust the fixed settlement rates pursuant to the foregoing in this clause (3) until the earliest of these triggering events occurs; and

• we will readjust the fixed settlement rates to the extent any of these rights, options or warrants are not exercised before they expire; provided that the rights, options or warrants trade together with our Common Stock and will be issued in respect of future issuances of the shares of our Common Stock.

With respect to an adjustment pursuant to this clause (3) where there has been a payment of a dividend or other distribution on our Common Stock of shares of capital stock of any class or series, or similar equity interest, of or relating to a subsidiary or other business unit, that are, or, when issued, will be, listed or admitted for trading on a U.S. national securities exchange, which we refer to as a “spin-off,” each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	FMV0 + MP0
	MP0

where,

CR0	=	such fixed settlement rate in effect immediately prior to the open of business on the ex-date for the spin-off;
CR1	=	such fixed settlement rate in effect immediately after the open of business on the ex-date for the spin-off;
FMV0	=	the average VWAP per share of the capital stock or similar equity interest distributed to holders of our Common Stock applicable to one share of our Common Stock over the ten consecutive trading day period commencing on, and including, the ex-date for the spin-off, or the “valuation period”; and
MP0	=	the average VWAP per share of our Common Stock over the valuation period.

The increase to each fixed settlement rate under the preceding paragraph will be calculated as of the close of business on the last trading day of the valuation period but will be given retroactive effect as of immediately after

the open of business on the ex-date of the spin-off. Because we will make the adjustment to each fixed settlement rate with retroactive effect, we will delay the settlement of any purchase contract where any date for determining the number of shares of our Common Stock issuable to a holder occurs during the valuation period until the second business day after the last trading day of such valuation period. If such dividend or distribution is not so paid, each fixed settlement rate shall be decreased, effective as of the date our board of directors or a committee thereof determines not to make or pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.

(4) If any cash dividend or distribution is made to all or substantially all holders of our Common Stock, each fixed settlement rate will be adjusted based on the following formula:

CR1 = CR0 x	SP0
	SP0 - C

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such dividend or distribution;
CR1	=	such fixed settlement rate in effect immediately after the close of business on the record date for such dividend or distribution;
SP0	=	the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the Trading Day immediately preceding the ex-date for such distribution; and
C	=	the amount in cash per share we distribute to all or substantially all holders of our Common Stock.

Any increase made under this clause (4) shall become effective immediately after the close of business on the record date for such dividend or distribution. If such dividend or distribution is not so paid, each fixed settlement rate shall be decreased, effective as of the date our board of directors or a committee thereof determines not to make or pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.

Notwithstanding the foregoing, if “C” (as defined above) is equal to or greater than “SP0” (as defined above), in lieu of the foregoing increase, each holder shall receive, in respect of each purchase contract, at the same time and upon the same terms as holders of shares of our Common Stock, without having to settle such purchase contract, the amount of cash that such holder would have received if such holder owned a number of shares of our Common Stock equal to the maximum settlement rate on the record date for such cash dividend or distribution.

(5) If we or any of our subsidiaries make a payment in respect of a tender or exchange offer for our Common Stock, to the extent that the cash and value of any other consideration included in the payment per share of Common Stock exceeds the average VWAP per share of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender or exchange offer, or the “expiration date”, each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	AC + (SP1x OS1)
	OS0 x SP1

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the expiration date;
CR1	=	such fixed settlement rate in effect immediately after the close of business on the expiration date;
AC	=	the aggregate value of all cash and any other consideration (as determined by our board of directors in good faith) paid or payable for shares purchased in such tender or exchange offer;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the expiration date (prior to giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer);
OS1	=	the number of shares of our Common Stock outstanding immediately after the expiration date (after giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer); and
SP1	=	the average VWAP of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the expiration date (the “averaging period”).

The increase to each fixed settlement rate under the preceding paragraph will be calculated at the close of business on the last trading day of the averaging period but will be given retroactive effect as of immediately after the close of business on the expiration date. Because we will make the adjustment to each fixed settlement rate with retroactive effect, we will delay the settlement of any purchase contracts where any date for determining the number of shares of our Common Stock issuable to a holder occurs during the averaging period until the second business day after the last trading day of such averaging period. For the avoidance of doubt, no adjustment under this clause (5) will be made if such adjustment would result in a decrease in any fixed settlement rate.

In the event that we or one of our subsidiaries is obligated to purchase shares of Common Stock pursuant to any such tender offer or exchange offer, but we or such subsidiary is permanently prevented by applicable law from effecting any such purchases, or all such purchases are rescinded, then each fixed settlement rate shall again be adjusted to be such fixed settlement rate that would then be in effect if such tender offer or exchange offer had not been made (or had been made only in respect of the purchases that have been made and not rescinded).

We may, to the extent permitted by law and the rules of NYSE or any other securities exchange on which our Common Stock or the purchase contracts is then listed, increase each fixed settlement rate by any amount for a period of at least 20 business days if such increase is irrevocable during such 20 business days and our board of directors (or a committee thereof) determines that such increase would be in our best interest. In addition, we may make such increases in each fixed settlement rate as we deem advisable in order to avoid or diminish any income tax to holders of our Common Stock resulting from any dividend or distribution of shares of our Common Stock (or issuance of rights or warrants to acquire shares of our Common Stock) or from any event treated as such for income tax purposes or for any other reason. We may only make such a discretionary adjustment if we make the same proportionate adjustment to each fixed settlement rate.

Beneficial owners of the purchase contracts may, in certain circumstances, including upon a distribution of cash dividends to holders of our shares of Common Stock, be deemed to have received a distribution subject to U.S. federal income tax as a dividend as a result of an adjustment or the nonoccurrence of an adjustment to the fixed settlement rates. See “Material United States Federal Income Tax Consequences.”

If we have a rights plan in effect upon settlement of the purchase contracts into Common Stock, the holder will receive, in addition to any shares of Common Stock received in connection with such settlement, the rights under the rights plan. However, if, prior to any settlement, the rights have separated from the shares of Common Stock in accordance with the provisions of the applicable rights plan, each fixed settlement rate will be adjusted at the time of

separation as if we distributed to all or substantially all holders of our Common Stock, shares of our capital stock, evidences of indebtedness, assets, property, rights, options or warrants as described in clause (3) above, subject to readjustment in the event of the expiration, termination or redemption of such rights. We do not currently have a stockholder rights plan in effect.

Adjustments to the fixed settlement rates will be calculated to the nearest 1/10,000th of a share of our Common Stock, and corresponding adjustments to the reference price and the threshold appreciation period will be calculated to the nearest $0.0001.

The fixed settlement rate will not be adjusted:

• upon the issuance of any shares of our Common Stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in Common Stock under any plan;

• upon the issuance of any shares of our Common Stock or options, rights or warrants to purchase those shares pursuant to any present or future benefit or other incentive plan or program of or assumed by us or any of our subsidiaries;

• subject to the second immediately preceding paragraph, upon the issuance of any shares of our Common Stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security not described in the preceding bullet and outstanding as of the date the purchase contracts were first issued;

• for a change in the par value of our Common Stock;

• for stock repurchases that are not tender or exchange offers referred to in clause (5) of the adjustments above, including structured or derivative transactions or pursuant to a stock repurchase program approved by our board of directors that is not a tender or exchange offer referred to in clause (5).

Except as otherwise provided above, we will be responsible for making all calculations called for under the purchase contracts. These calculations include, but are not limited to, determinations of the fundamental change early settlement rate, the stock price in connection with a fundamental change, the daily VWAP, the average VWAPs and the fixed settlement rates of the purchase contracts.

We will be required, within ten business days after the fixed settlement rates are adjusted, to provide or cause to be provided written notice of the adjustment to the holders of the purchase contracts. We will also deliver to the purchase contract agent a certificate setting forth in reasonable detail the method by which the adjustment to each fixed settlement rate was determined and setting forth each adjusted fixed settlement rate.

For the avoidance of doubt, if an adjustment is made to the fixed settlement rates, no separate inversely proportionate adjustment will be made to the reference price or the threshold appreciation price because the reference price is equal to $100 divided by the maximum settlement rate (as adjusted in the manner described herein) and the threshold appreciation price is equal to $100 divided by the minimum settlement rate (as adjusted in the manner described herein).

Whenever the terms of the purchase contracts require us to calculate the daily VWAP per share of our Common Stock over a span of multiple days, our board of directors will make appropriate adjustments in good faith (including, without limitation, to the applicable market value, the early settlement rate or the fundamental change early settlement rate (as the case may be)) to account for any adjustments to the fixed settlement rates (as the case may be) that become effective, or any event that would require such an adjustment if the record date, ex-date, effective date or expiration date (as the case may be) of such event occurs, during the relevant period used to calculate such prices or values (as the case may be).

If:

• the record date for a dividend or distribution on shares of our Common Stock occurs after the end of the 20 consecutive trading day period used for calculating the applicable market value and before the purchase contract settlement date; and

• that dividend or distribution would have resulted in an adjustment of the number of shares issuable to the holders of the purchase contracts had such record date occurred on or before the last trading day of such 20-trading day period,

then we will deem the holders of the purchase contracts to be holders of record of our Common Stock for purposes of that dividend or distribution. In this case, the holders of the purchase contracts would receive the dividend or distribution on our Common Stock together with the number of shares of our Common Stock issuable upon settlement of the purchase contracts.

Recapitalizations, Reclassifications and Changes of Our Common Stock

In the event of:

• any consolidation or merger of us with or into another person;

• any sale, transfer, lease or conveyance to another person of all or substantially all of our property and assets;

• any reclassification of our Common Stock into securities (other than a share split or share combination), including securities other than our Common Stock; or

• any statutory exchange of our securities with another person (other than in connection with a consolidation or merger),

in each case, as a result of which our Common Stock would be converted into, or exchanged for, stock, other securities or other property or assets (including cash or any combination thereof) (each, a “reorganization event”), each purchase contract outstanding immediately prior to such reorganization event shall, without the consent of the holders of the purchase contracts, become a contract to purchase the kind of stock, other securities or other property or assets (including cash or any combination thereof) that a holder of our Common Stock would have been entitled to receive in connection with such reorganization event (such stock, other securities or other property or assets (including cash or any combination thereof), the “exchange property”, with each “unit of exchange property” meaning the kind and amount of exchange property that a holder of one share of our Common Stock would have received in such reorganization event) and, prior to or at the effective time of such reorganization event, we or the successor or purchasing person, as the case may be, shall execute with the purchase contract agent a supplemental agreement pursuant to the purchase contract agreement and the purchase contracts to provide for such change in the right to settle the purchase contracts.

If the transaction causes our Common Stock to be converted into, or exchanged for, the right to receive more than a single type of consideration (determined based in part upon any form of stockholder election), the exchange property underlying the purchase contracts will be deemed to be the weighted average of the types and amounts of consideration actually received by the holders of our Common Stock in such reorganization event.

The number of units of exchange property we will deliver upon the settlement of each purchase contract following the effective date of such reorganization event will be determined as if references to our Common Stock deliverable upon settlement of the purchase contracts on the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be, were to units of exchange property (without interest thereon and without any right to dividends or distributions thereon which have a record date prior to the date on which holders of the purchase contracts become holders of record of the underlying shares of our Common Stock). For the purpose of determining which bullet of the definition of settlement rate in the second paragraph under “-Delivery of Common Stock” will apply upon settlement of each purchase contract, and for the purpose of calculating the settlement rate if the second bullet is applicable, the value of a unit of exchange property will be determined in good faith by our board of directors (which determination will be final), except that if a unit of exchange property

includes Common Stock or American Depositary Receipts, or “ADRs”, that are traded on a U.S. national securities exchange, the value of such Common Stock or ADRs will be the average over the 20 consecutive trading day period used for calculating the applicable market value of the volume-weighted average prices for such Common Stock or ADRs, as displayed on the applicable Bloomberg screen (as determined in good faith by our board of directors (which determination will be final)); or, if such price is not available, the average market value per share of such Common Stock or ADRs over such period as determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained by us for this purpose. The provisions of this paragraph will apply to successive reorganization events, and the provisions summarized under “-Anti-dilution Adjustments to the Fixed Settlement Rates” will apply to any shares of common equity or ADRs of us or any successor received by the holders of shares of our Common Stock in any such reorganization event. We (or any successor to us) will, as soon as reasonably practicable (but in any event within five calendar days) after the occurrence of any reorganization event provide written notice to the holders of the purchase contracts of such occurrence and of the kind and amount of cash, securities or other property that constitute the exchange property. Failure to deliver such notice will not affect the operation of the provisions described in this section.

It is possible that certain consolidations, mergers, combinations or other transactions could result in tax gains or losses to the holders either as a result of the transaction or the conversion thereafter. Holders are encouraged to consult with their own tax advisors regarding the tax consequences of the ownership, disposition and settlement of the purchase contracts.

Fractional Shares

No fractional shares of our Common Stock will be issued to holders upon settlement of the purchase contracts. In lieu of fractional shares otherwise issuable, holders will be entitled to receive an amount in cash equal to the fraction of a share of our Common Stock, calculated on an aggregate basis in respect of the purchase contracts being settled (provided that, so long as the Equity Units are in global form, we may elect to aggregate Equity Units for purposes of these calculations on any basis permitted by the applicable procedures of DTC), multiplied by the daily VWAP of our Common Stock on the trading day immediately preceding the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be.

Legal Holidays

In any case where the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be, shall not be a business day, notwithstanding any term to the contrary in the purchase contract agreement or purchase contract, the settlement of the purchase contracts shall not be effected on such date, but instead shall be effected on the next succeeding business day with the same force and effect as if made on such settlement date, and no interest or other amounts shall accrue or be payable by us or to any holder in respect of such delay.

Consequences of Bankruptcy

Pursuant to the terms of the purchase contract agreement, the purchase contract settlement date for each purchase contract, whether held separately or as part of an Equity Unit, will automatically accelerate upon the occurrence of specified events of bankruptcy, insolvency or reorganization with respect to us. Pursuant to the terms of the purchase contract agreement, upon acceleration, holders will be entitled under the terms of the purchase contracts to receive a number of shares of our Common Stock per purchase contract equal to the maximum settlement rate in effect immediately prior to such acceleration (regardless of the market value of our Common Stock at that time). However, a bankruptcy court may prevent us from delivering our Common Stock in settlement of the accelerated purchase contracts. In such event, a holder would have a damage claim against us for the value of the Common Stock that we would have otherwise been required to deliver upon settlement of the purchase contracts. Any such damage claim that holders have against us following such acceleration will rank pari passu with the claims of holders of our Common Stock in the relevant bankruptcy proceeding. As such, to the extent we fail to deliver Common Stock to the holder upon such an acceleration, the holder will only be able to recover damages to the extent holders of our Common Stock receive any recovery.

Modification

The purchase contract agreement contains provisions permitting us and the purchase contract agent to modify the purchase contract agreement or the purchase contracts without the consent of the holders of purchase contracts (whether held separately or as a component of Equity Units) for any of the following purposes:

• to evidence the succession of another person to us, and the assumption by any such successor of the covenants and obligations of ours in the purchase contract agreement and the units and separate purchase contracts, if any;

• to add to the covenants for the benefit of holders of purchase contracts or to surrender any of our rights or powers under the agreement;

• to evidence and provide for the acceptance of appointment of a successor purchase contract agent;

• upon the occurrence of a reorganization event, solely (i) to provide that each purchase contract will become a contract to purchase exchange property and (ii) to effect the related changes to the terms of the purchase contracts, in each case, as required by the applicable provisions of the purchase contract agreement;

• to conform the provisions of the purchase contract agreement to the “Description of the Purchase Contracts” and “Description of the Equity Units” sections in the preliminary prospectus supplement which forms a part of the registration statement on which the Equity Units are registered, as supplemented by the related pricing term sheet;

• to cure any ambiguity or manifest error, to correct or supplement any provisions that may be inconsistent or defective; and

• to make any other provisions with respect to such matters or questions, so long as such action does not adversely affect the interest of the holders in any material respect.

The purchase contract agreement contains provisions permitting us and the purchase contract agent, with the consent of the holders of not less than a majority of the purchase contracts at the time outstanding, to modify the terms of the purchase contracts or the purchase contract agreement. However, no such modification may, without the consent of the holder of each outstanding purchase contract affected by the modification,

• reduce the number of shares of Common Stock deliverable upon settlement of the purchase contract (except to the extent expressly required pursuant to the anti-dilution adjustments);

• change the purchase contract settlement date, or adversely modify the early settlement right or the fundamental change early settlement right; or

• reduce the above-stated percentage of outstanding purchase contracts the consent of the holders of which is required for the modification or amendment of the provisions of the purchase contracts or the purchase contract agreement.

In executing any modification, the purchase contract agent shall be entitled to receive an opinion of counsel and an officer’s certificate stating that such modification is authorized or permitted under the terms of the purchase contract agreement.

Consolidation, Merger, Sale or Conveyance

Under the purchase contract agreement, we are permitted to consolidate with or merge with or into another company. We are also permitted to sell, assign, transfer, lease or convey all or substantially all of our assets to another company. However, if we take any of these actions, we must meet the following conditions:

• the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall expressly assume all of our obligations under the purchase contracts and the purchase contract agreement;

• the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall be a corporation organized and existing under the laws of the United States or any state thereof or the District of Columbia; and

• immediately after the merger, consolidation, sale, assignment, transfer, lease or conveyance, no default has occurred and is continuing under the purchase contracts or the purchase contract agreement.

Reservation of Common Stock

We will at all times reserve and keep available out of our authorized and unissued Common Stock, solely for issuance upon settlement of the purchase contracts, the number of shares of Common Stock that would be issuable upon the settlement of all purchase contracts then outstanding, assuming settlement at the maximum settlement rate.

Governing Law

The purchase contract agreement, the Equity Units and the purchase contracts is governed by, and construed in accordance with, the laws of the State of New York.

Information Concerning the Purchase Contract Agent

The Bank of New York Mellon Trust Company, N.A. is the purchase contract agent. The purchase contract agent acts as the agent for the holders of Equity Units and separate purchase contracts from time to time. The purchase contract agreement does not obligate the purchase contract agent to exercise any discretionary actions in connection with a default under the terms of the purchase contracts or the purchase contract agreement.

The purchase contract agreement contains provisions limiting the liability of the purchase contract agent. The purchase contract agreement contains provisions under which the purchase contract agent may resign or be replaced. This resignation or replacement would be effective upon the acceptance of appointment by a successor purchase contract agent.

We maintain banking relationships in the ordinary course of business with the purchase contract agent and its affiliates.

Calculations in Respect of Purchase Contracts

We will be responsible for making all calculations called for under the Equity Units and any separate purchase contracts. The purchase contract agent will have no obligation to make, review or verify any such calculations. All such calculations made by us will be made in good faith and, absent manifest error, will be final and binding on the purchase contract agent and the holders of the Equity Units and any separate purchase contracts. We will provide a schedule of such calculations to the purchase contract agent and the purchase contract agent will be entitled to conclusively rely upon the accuracy of such calculations without independent verification.

Description of the U.S. Treasury Strips Components

The U.S. treasury strips underlying the Equity Units are held by the custodian as agent for the holders of the Equity Units and are subject to the terms of a custodial agreement between the custodian and purchase contract agent. The following summary contains a description of all of the material terms of the custodial agreement but is not complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the custodial agreement,

including the definitions in the custodial agreement of certain terms. We refer you to the custodial agreement which is incorporated by reference to this Annual Report on Form 10-K.

Each U.S. treasury strips component will initially form a part of an Equity Unit. On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, the holder will have the right to separate 48,000 Equity Units (or any integral multiples thereof), and withdraw the U.S. treasury strips underlying those Equity Units. Following such separation, U.S. treasury strips may be transferred separately from purchase contracts.

Payments of U.S. Treasury Strips

The U.S. treasury strips are held by the custodian as agent for the holders of the Equity Units. The custodian will, upon instructions from the purchase contract agent, forward to each holder of Equity Units the amount it receives from the U.S. government in respect of each U.S. treasury strip underlying the Equity Units owned by such holder on the business day immediately following the date such U.S. treasury strip matures on February 15, May 15, August 15 and November 15 of each year, with such payments commencing on, and including, August 17, 2020, and ending on, and including, August 16, 2023. We expect that the amount payable per Equity Unit per full quarter as described in the immediately preceding sentence will be equal to $1.3750, which represents an annual rate of return on the stated amount per Equity Unit of 5.50%. The amount payable per Equity Unit on August 17, 2020 was equal to $0.6875. These payments will consist of the pro rata amount of all amounts received by the custodian in respect of the U.S. treasury strips. So long as the Equity Units remain in the form of one or more book-entry, global Equity Unit certificates as described in “-Book-Entry Procedures and Settlement” below, the record date will be the business day prior to the relevant payment date. If the Equity Units do not remain in the form of one or more book-entry, global Equity Unit certificates, the relevant record date will be the fifteenth day (whether or not a business day) prior to the relevant payment date.

We have no obligation, responsibility or liability with respect to the purchase of the U.S. treasury strips and their delivery into the custody of the custodian, the performance or non-performance of the duties of the custodian or any payment of the U.S. treasury strips components. Goldman Sachs & Co. LLC has purchased the U.S. treasury strips to be sold to the purchasers of the Equity Units and delivered to the custodian, The Bank of New York Mellon Trust Company, N.A.

Each Equity Unit will initially evidence its holder’s 1/48,000th beneficial ownership interest in the following U.S. treasury strips, which will constitute one U.S. treasury strips component:

Maturity	Face Amount		CUSIP
August 15, 2020		$    33,000		912803AU7
November 15, 2020		$    66,000		912820WZ6
February 15, 2021		$    66,000		912803AV5
May 15, 2021		$    66,000		912803AW3
August 15, 2021		$    66,000		912821AG0
November 15, 2021		$    66,000		912820ZH3
February 15, 2022		$    66,000		912833LG3
May 15, 2022		$    66,000		912821BZ7
August 15, 2022		$    66,000		912820RU3
November 15, 2022		$    66,000		912820SH1
February 15, 2023		$    66,000		912820B30
May 15, 2023		$    66,000		912820F36
August 15, 2023		$    66,000		912820G84

Role of Custodian

The custodian is the agent of the holders of the Equity Units evidencing the U.S. treasury strips and is not a trustee, and no trust was intended to be created or was created by the terms of the custodial agreement. The custodian has no

managerial role nor any discretion with respect to the U.S. treasury strips and has no right to deal with the U.S. treasury strips except as specifically provided in the custodial agreement. The custodian agrees to hold the U.S. treasury strips and exercise the due care of a professional custodian for hire. Under the custodial agreement, the custodian is required to remit all payments received from the U.S. government in respect of the U.S. treasury strips to the holders of the Equity Units without making any deduction as instructed by the purchase contract agent.

Ownership of U.S. Treasury Strips

The U.S. treasury strips will at all times be the sole and exclusive property of the holders of the Equity Units. The custodian may not transfer, assign, pledge, set off or otherwise dispose of any of the U.S. treasury strips or any interests therein, except as expressly permitted by the provisions of the custodial agreement.

Withdrawal of U.S. Treasury Strips

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 Equity Units (or any integral multiple thereof) will have the right to separate such Equity Units and withdraw the U.S. treasury strips underlying those Equity Units. To withdraw the U.S. treasury strips underlying Equity Units, holders must follow the procedures outlined under the above caption “Description of the Equity Units-Separating and Recreating Equity Units-Separating Equity Units.” The purchase contract agent will then (i) cancel the Equity Units and deliver to the holder the purchase contracts evidenced by the Equity Units and (ii) instruct the custodian to deliver to the holder such holder’s U.S. treasury strips. Any administrative fees and expenses related to withdrawing the U.S. treasury strips evidenced by the Equity Units that are payable to the purchase contract agent or the custodian will be at the expense of the holder of Equity Units requesting withdrawal. To recreate the Equity Units, holders must follow the procedures outlined under the above caption “Description of the Equity Units-Separating and Recreating Equity Units-Recreation of Equity Units.” Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any separation or recreation of Equity Units may be made only in integral multiples of 48,000 Equity Units.

Certain Other Provisions of the Custodial Agreement

Delivery of U.S. Treasury Strips

Payments of the U.S. treasury strips components will be made by the custodian to the depositary as long as the Equity Units remain in book-entry form. In addition, if the Equity Units do not remain in book-entry form, payments may be made, at the option of the custodian, by check mailed to the address of the person entitled to the payments as shown on the Equity Unit register.

If the purchase contract settlement date is accelerated, U.S. treasury strips will be delivered by the custodian upon presentation and surrender of the Equity Unit certificates evidencing the related Equity Units at the office of the purchase contract agent or, in the case of book-entry Equity Units, upon presentation and surrender of the Equity Units in accordance with the procedures of the depositary. Following such acceleration and delivery, the custodian will sell (or, at the expense of holders, retain the services of a broker dealer that will sell) such U.S. treasury strips, and the custodian will distribute the net cash proceeds of such sale (less any expenses incurred by the custodian in connection with such sale) on a pro rata basis to holders of Equity Units (or in accordance with the procedures of the depositary in the case of global Equity Units). Until the Equity Unit certificate is presented and surrendered or the holder provides satisfactory evidence that the Equity Unit certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the purchase contract agent, the U.S. treasury strips will be held by the custodian for the account of the holder. The custodian will have no obligation to invest or to pay interest on any amounts held by the custodian pending delivery.

Modification

The custodial agreement contains provisions prohibiting the custodian and the purchase contract agent, except under limited circumstances, from modifying or amending the terms of the custodial agreement without the consent of the holder of each outstanding Equity Unit affected by the modification or amendment.

Governing Law

The custodial agreement is governed by, and construed in accordance with, the laws of the State of New York.

Information Concerning the Custodian

The Bank of New York Mellon Trust Company, N.A., whose designated office is located at 400 South Hope Street, Suite 500, Los Angeles, CA 90071, acts as the custodian of the U.S. treasury strips on behalf of the holders of Equity Units from time to time.

The custodial agreement does not obligate the custodian to perform any discretionary actions in connection with the terms of the Equity Units or the custodial agreement. The custodial agreement also contains provisions limiting the liability of the custodian and the circumstances under which the custodian may resign or be replaced. No such resignation or replacement will be effective until a successor custodian is appointed.

We maintain banking relationships in the ordinary course of business with the custodian and its affiliates.

Book Entry Procedures and Settlement

Except in the limited circumstances described herein, the Equity Units and the purchase contracts are issued in the form of one or more global Equity Unit certificates and global purchase contract certificates, respectively, held by the purchase contract agent, as custodian for, and registered in the name of, The Depository Trust Company (“DTC”), as depositary, or its nominee.

The depositary has advised us as follows: The depositary is a limited-purpose trust company organized under the Banking Law of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to Section 17A of the U.S. Securities Exchange Act of 1934 (the “Exchange Act”). The depositary was created to hold securities of its participants (defined below) and to facilitate the clearance and settlement of transactions among its participants in such securities through electronic book-entry changes in accounts of the participants, thereby eliminating the need for physical movement of certificates. The depositary’s participants include securities brokers and dealers, banks, trust companies, clearing corporations and some other organizations, some of whom (and/or their representatives) own the depositary. Access to the depositary’s book-entry system is also available to others, such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly.

No Equity Unit represented by global Equity Unit certificates and no purchase contract represented by global purchase contract certificates may be exchanged in whole or in part for definitive Equity Units or purchase contracts, as the case may be, and no transfer of global Equity Unit certificates and global purchase contract certificates in whole or in part may be registered, in the name of any person other than the depositary or any nominee of the depositary unless:

• the depositary has notified the purchase contract agent that it is unwilling or unable to continue as depositary for such global Equity Unit certificates or global purchase contract certificates, as the case may be, or has ceased to be qualified to act as such as required by the purchase contract agreement;

• there shall have occurred and be continuing a default by us in respect of our obligations under the purchase contract agreement; or

• the beneficial holder of Equity Units elects to withdraw the U.S. treasury strips evidenced by one or more of its Equity Units and elects to hold the purchase contracts in definitive form.

All Equity Units and purchase contracts represented by one or more global Equity Unit certificates and global purchase contract certificates, respectively, or any portion thereof are registered in such names as the depositary may have directed.

The laws of some jurisdictions require that some purchasers of Equity Units take physical delivery of the Equity Units in definitive form. These laws may impair a holder’s ability to transfer beneficial interests in Equity Units so long as they are represented by global Equity Unit certificates.

As long as the depositary (or its nominee) is the registered owner of the global Equity Unit certificates and the global purchase contract certificates, the depositary (or its nominee) will be considered the sole owner and holder of the global Equity Unit certificates, the global purchase contract certificates and all Equity Units and purchase contracts represented thereby for all purposes under the Equity Units and purchase contracts and the purchase contract agreement. Except in the limited circumstances referred to above, owners of beneficial interests in global Equity Unit certificates and owners of beneficial interests in global purchase contract certificates:

• are not be entitled to have the global purchase contract certificates or the purchase contracts represented thereby registered in their respective names;

• will not receive or be entitled to receive physical delivery of Equity Unit certificates or purchase contract certificates, as the case may be, in exchange therefor; and

• are not be considered to be owners or holders of global Equity Unit certificates or any Equity Units represented thereby or global purchase contract certificates or any purchase contracts represented thereby, for any purpose under the Equity Units, the purchase contracts or the purchase contract agreement.

All transfers and deliveries of shares of our Common Stock (and any cash amount paid by us in lieu of fractional shares) issued on settlement of the purchase contracts evidenced by the Equity Units in global form and all transfers and deliveries of the U.S. treasury strips evidenced by the Equity Units in global form will be made to the depositary (or its nominee) as the holder thereof. All transfers and deliveries of shares of our Common Stock (and any cash amount paid by us in lieu of fractional shares) pursuant to the purchase contracts represented by the global purchase contract certificates will be made by the purchase contract agent to the depositary (or its nominee) as the holder thereof. Cash payments in respect of the U.S. treasury strips component of Equity Units in global form will be made by the custodian, at the direction of the purchase contract agent, to the depositary (or its nominee) as the holder of such Equity Units.

Ownership of beneficial interests in the global Equity Unit certificates and global purchase contract certificates is limited to participants or persons that may hold beneficial interests through institutions that have accounts with the depositary or its nominee, which we refer to as participants. Ownership of beneficial interests in global Equity Unit certificates and global purchase contract certificates will be shown only on, and the transfer of those ownership interests will be effected only through, records maintained by the depositary or its nominee (with respect to participants’ interests) or any such participant (with respect to interests of persons held by such participants on their behalf). Procedures for settlement of purchase contracts on the purchase contract settlement date or upon early settlement for holders who hold in book-entry form will be governed by arrangements among the depositary, participants and persons that may hold beneficial interests through participants designed to permit such settlement without the physical movement of certificates. Payments, transfers, deliveries, exchanges and other matters relating to beneficial interests in global Equity Unit certificates may be subject to various policies and procedures adopted by the depositary from time to time. None of PG&E Corporation, the purchase contract agent or the custodian or any of their respective agents will have any responsibility or liability for any aspect of the depositary’s or any participant’s records relating to, or for payments made on account of, beneficial interests in global Equity Unit certificates or global purchase contract certificates, or for maintaining, supervising or reviewing any of the depositary’s records or any participant’s records relating to such beneficial ownership interests.

Notices

So long as the global securities are held on behalf of DTC or any other clearing system, notices to holders of securities represented by a beneficial interest in the global securities may be given by delivery of the relevant notice to DTC or the alternative clearing system, as the case may be.

EX-4.62(B)

EXHIBIT 4.62(b)

DESCRIPTION OF PACIFIC GAS AND ELECTRIC COMPANY’S

SECURITIES REGISTERED UNDER

SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

Description of Preferred Stock

The following description of Pacific Gas and Electric Company’s (the “Utility”) preferred stock is only a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to applicable law, our Amended and Restated Articles of Incorporation effective as of June 22, 2020 (the “Articles of Incorporation”) and Bylaws amended and restated as of May 20, 2021 (the “Bylaws”), each of which is filed as an exhibit to this Annual Report on Form 10-K and is incorporated by reference herein. We encourage you to read the Articles of Incorporation and the Bylaws for additional information.

In this section, references to “we,” “our,” “ours” and “us” refer only to the Utility and not to any of its direct or indirect parents, subsidiaries or affiliates except as expressly provided.

General

Our Articles of Incorporation authorize the issuance of 800,000,000 shares of common stock with a par value of $5 per share, 75,000,000 shares of first preferred stock with a par value of $25 per share (the “First Preferred Stock”), and 10,000,000 of $100 first preferred stock, cumulative, with a par value of $100 per share (the “$100 First Preferred Stock” and, together with the First Preferred Stock, the “Preferred Stock”).

All outstanding shares of our common stock are owned by PG&E Corporation. There are no shares of $100 First Preferred Stock outstanding. First Preferred Stock is issued and outstanding in the following series:

•6% nonredeemable (“6% Nonredeemable First Preferred Stock”)

•5.50% nonredeemable (“5.5% Nonredeemable First Preferred Stock”)

•5% nonredeemable (“5% Nonredeemable First Preferred Stock”)

•5% redeemable (“5% First Preferred Stock”)

•5% series A redeemable (“5% First Preferred Series A Stock”)

•4.80% redeemable (“4.8% First Preferred Stock”)

•4.50% redeemable (“4.5% First Preferred Stock”)

•4.36% series A redeemable (“4.36% First Preferred Stock”)

As of December 31, 2022, the Utility’s First Preferred Stock outstanding included:

•4,211,661 shares of 6% Nonredeemable First Preferred Stock;

•1,173,163 shares of 5.5% Nonredeemable First Preferred Stock;

•400,000 shares of 5% Nonredeemable First Preferred Stock;

•1,778,172 shares of 5% First Preferred Stock;

•934,322 shares of 5% First Preferred Series A Stock;

•793,031 shares of 4.8% First Preferred Stock;

•611,142 shares of 4.5% First Preferred Stock; and

•418,291 shares of 4.36% First Preferred Stock.

Under the Articles of Incorporation, the Board of Directors of the Utility is authorized without further shareholder action to provide for the issuance of Preferred Stock up to the amounts authorized by the Articles of Incorporation, in one or more series, with such rights, preferences, privileges and restrictions as shall be stated and expressed in the resolution or resolutions providing for the issue of such Preferred Stock, or series thereof, adopted, at any time or from time to time, by the Board of Directors.

Voting Rights

Except as otherwise provided by law, holders of our Preferred Stock have voting rights on the basis of one vote per share on each matter submitted to a vote at a meeting of shareholders. Our shareholders may not cumulate votes in elections of directors. As a result, the holders of our Preferred Stock entitled to exercise more than 50% of the voting rights in an election of directors can elect all of the directors to be elected if they choose to do so. In such event, the holders of the remaining Preferred Stock voting for the election of directors will not be able to elect any persons to the Board of Directors.

Dividend Rights

The owners and holders of shares of Preferred Stock, when issued as fully paid, are entitled to receive, from the date of issue of such share, out of funds legally available therefor, cumulative preferential dividends, when and as declared by the Board of Directors, at the following rates upon the par value of their respective shares, and not more:

•6% per year upon the 6% Nonredeemable First Preferred Stock

•5.5% per year upon the 5.5% Nonredeemable First Preferred Stock

•5% per year upon the 5% First Preferred Series A Stock, 5% First Preferred Stock and 5% Nonredeemable First Preferred Stock

•4.8% per year upon the 4.8% First Preferred Stock

•4.5% per year upon the 4.5% First Preferred Stock

•4.36% per year upon the 4.36% First Preferred Stock

Such dividends shall be declared and shall be either paid or set apart for payment before any dividend upon the shares of common stock shall be either declared or paid. All shares of Preferred Stock rank equally in priority with regard to preference in dividend rights, except that shares of different classes or different series thereof may differ as to the amounts of dividends to which they are entitled.

Liquidation Rights

Upon the liquidation or dissolution of the Utility at any time and in any manner, the owners and holders of Preferred Stock issued as fully paid will be entitled to receive an amount equal to the par value of such shares plus an amount equal to all accumulated and unpaid dividends thereon to and including the date fixed for such distribution or payment before any amount shall be paid to the holders of the Utility’s common stock. All shares of Preferred Stock rank equally in priority with regard to preference in liquidation rights, except that shares of different classes or different series thereof may differ as to the amounts of liquidation payments to which they are entitled. All shares of Preferred Stock rank senior to common stock with regard to liquidation rights.

If any share or shares of Preferred Stock shall at any time be issued as only partly paid, the owners and holders of such partly paid share or shares shall have the right to receive dividends and to share in the assets of the Utility upon its liquidation or dissolution in all respects like the owners and holders of fully paid shares of Preferred

Stock, except that such right shall be only in proportion to the amount paid on account of the subscription price for which such partly paid share or shares shall have been issued.

Conversion, Redemption and Preemptive Rights

None of the 6% Nonredeemable First Preferred Stock, 5.5% Nonredeemable First Preferred Stock and 5% Nonredeemable First Preferred Stock is subject to redemption.

The remaining outstanding series of First Preferred Stock, and any Preferred Stock issued in the future, may be redeemed at the Utility’s option, at any time or from time to time, at the redemption price fixed for such series of Preferred Stock together with accumulated and unpaid dividends at the rate fixed therefor to and including the date fixed for redemption. If less than all the outstanding shares of any such series are to be redeemed, the shares to be redeemed shall be determined pro rata or by lot in such manner as the Board of Directors may determine. There is no restriction on the repurchase or redemption of Preferred Stock by the Utility while there is any arrearage in the payment of dividends or sinking fund payments.

Unless the certificate of determination for any series of Preferred Stock shall otherwise provide, notice of every redemption shall be published in a newspaper of general circulation in the City and County of San Francisco, State of California, and in a newspaper of general circulation in the Borough of Manhattan, City and State of New York, at least once in each of two (2) successive weeks, commencing not earlier than sixty (60) nor later than thirty (30) days before the date fixed for redemption; successive publications need not be made in the same newspaper. A copy of such notice shall be mailed within the same period of time to each holder of record, as of the record date, of the shares to be redeemed, but the failure to mail such notice to any shareholder shall not invalidate the redemption of such shares.

From and after the date fixed for redemption, unless default be made by the Utility in paying the amount due upon redemption, dividends on the shares called for redemption shall cease to accrue, and such shares shall be deemed to be redeemed and shall be no longer outstanding, and the holders thereof shall cease to be shareholders with respect to such shares and shall have no rights with respect thereto except the right to receive from the Utility upon surrender of their certificates the amount payable with respect thereto upon redemption without interest.

None of the Preferred Stock has preemptive rights or conversion rights.

Non-Assessability

Shares of Preferred Stock, the subscription price of which shall have been paid in full, whether such price be par or more or less than par, shall be issued as fully paid shares and shall never be subject to any call or assessment for any purpose whatever. Shares of Preferred Stock, only a part of the subscription price of which shall have been paid, shall be subject to calls for the unpaid balance of the subscription price thereof. But no call made on partly paid Preferred Stock or partly paid common stock shall be recoverable by action or be enforceable otherwise than by sale or forfeiture of delinquent stock in accordance with the applicable provisions of the Corporations Code of California.

If at any time, whether by virtue of any amendment of the Articles of Incorporation or any amendment or change of the law of the State of California relating to corporations or otherwise, any assessment shall, in any event whatsoever, be levied and collected on any subscribed and issued shares of Preferred Stock after the subscription price thereof shall have been paid in full, the rights of the owners and holders thereof to receive dividends and their rights to share in the assets upon the liquidation or dissolution of the Utility shall, immediately upon the payment of such assessment and by virtue thereof, be increased in the same ratio as the total amount of the assessment or assessments so levied and collected shall bear to the par value of such shares of Preferred Stock.

Listing

The outstanding series of First Preferred Stock are listed on the NYSE American as follows:

•6% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PA

•5.5% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PB

•5% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PC

•5% First Preferred Stock is listed under trading symbol PCG-PD

•5% First Preferred Series A Stock is listed under the trading symbol PCG-PE

•4.8% First Preferred Stock is listed under trading symbol PCG-PG

•4.5% First Preferred Stock is listed under trading symbol PCG-PH

•4.36% First Preferred Series A Stock is listed under trading symbol PCG-PI

Transfer Agent

The transfer agent for our Preferred Stock is EQ Shareowner Services.

EX-10.37

EXHIBIT 10.37

Execution Version

AMENDMENT NO. 1 TO CREDIT AGREEMENT

This AMENDMENT NO. 1, dated as of September 23, 2022 (this “Amendment”), is entered into by and among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), each lender party hereto (the “Lenders”) and BANK OF AMERICA, N.A., as administrative agent (in such capacity, the “Administrative Agent”).

RECITALS:

WHEREAS, reference is hereby made to the Credit Agreement, dated as of April 20, 2022, among the Borrower, the Lenders and the Administrative Agent (the “Credit Agreement”), capitalized terms used (including in the preamble and recitals hereto) but not defined herein shall have the meanings assigned to such terms in the Credit Agreement; and

WHEREAS, the Borrower has requested, and the Required Lenders have agreed, to amend the Credit Agreement on the terms and subject to the conditions set forth in this Amendment.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration (the receipt and sufficiency of which is hereby acknowledged), the parties hereto hereby agree as follows:

A.    Amendments to Credit Agreement. On the Amendment No. 1 Effective Date (as defined below), the Credit Agreement is hereby amended as follows:

(i)    Section 1.1 of the Credit Agreement is hereby amended by deleting the following definitions in their entirety:

“Cash Management Agreement”

“Indebtedness Covenant Release Date”

“Permitted Refinancing”

“Utility Revolving Credit Agreement”

(ii)    Section 7.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Section 7.1    Reserved.”

(iii)    Section 7.5 of the Credit Agreement is hereby amended by amending and restating the proviso thereof in its entirety to read as follows:

“provided that, in each case, if such sale and leaseback results in a Capital Lease Obligation, any Lien made the subject of such Capital Lease Obligation is permitted by Section 7.3.”

(iv)    Section 8(c) of the Credit Agreement is hereby amended by amending and restating the proviso thereof in its entirety to read as follows:

“(c)    the Borrower shall default in the observance or performance of any agreement contained in Section 6.4(a)(i), Section 6.7(a), Section 6.10, Section 7.2, Section 7.3 or Section 7.4 of this Agreement; or”

B.    Conditions Precedent. This Amendment shall become effective as of the date first above written when each of the following conditions precedent shall have been satisfied (the “Amendment No. 1Effective Date”):

1.    Executed Counterparts. The Administrative Agent shall have received a counterpart to this Amendment duly executed by the Borrower and the Required Lenders;

2.    Representations and Warranties. The representations and warranties of the Borrower contained in Section 4 of the Credit Agreement (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13) shall be true and correct in all material respects immediately prior to and immediately after giving effect to this Amendment; provided that each of such representations and warranties that contains a materiality qualification shall be true and correct on and as of the Amendment No. 1 Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date);

3.    No Default. No Default or Event of Default shall have occurred and be continuing immediately prior to, and immediately after giving effect to, the Amendment No. 1 Effective Date; and

4.    Fees and Expenses. On or prior to the Amendment No. 1 Effective Date, the Borrower shall have paid all reasonable out-of-pocket costs and expenses of the Administrative Agent required to be paid or reimbursed by the Borrower in connection with the preparation, negotiation, execution and delivery of this Amendment and related documentation (including, in each case, without limitation, the reasonable fees and disbursements of counsel for the Administrative Agent with respect thereto).

C.    Other Terms.

1.    Reference to the Effect on the Loan Documents.

(i)    As of the Amendment No. 1 Effective Date, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, and each reference in the other Loan Documents to the “Credit Agreement” (including, without limitation, by means of words like “thereunder,” “thereof” and words of like import), shall mean and be a reference to the Credit Agreement as amended hereby, and this Amendment and the Credit Agreement shall be read together and construed as a single instrument.

(ii)    Except as expressly amended hereby or specifically waived above, all of the terms and provisions of the Credit Agreement and all other Loan Documents are and shall remain in full force and effect and are hereby ratified and confirmed.

(iii)    The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders, the Borrower, or the Administrative Agent under any of the Loan Documents, nor constitute a waiver or amendment of any other provision of any of the Loan Documents or for any purpose except as expressly set forth herein.

(iv)    This Amendment is a Loan Document.

2.    Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

Delivery of an executed counterpart of a signature page of this Amendment that is an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record (each, an “Electronic Signature”) transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Amendment shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be.

3.    Ratification. This Amendment shall be effective pursuant to Section 10.1 of the Credit Agreement (and approved and ratified by the Lenders (including in their capacity as Required Lenders) and the Administrative Agent for all purposes under the Loan Documents).

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4.    Governing Law. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

5.    Section Titles. The section titles contained in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto, except when used to reference a section.

6.    Notices. All communications and notices hereunder shall be given as provided in the Credit Agreement.

7.    Severability. The fact that any term or provision of this Amendment is held invalid, illegal or unenforceable as to any person in any situation in any jurisdiction shall not affect the validity, enforceability or legality of the remaining terms or provisions hereof or the validity, enforceability or legality of such offending term or provision in any other situation or jurisdiction or as applied to any person.

8.    Successors. The terms of this Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.

9.    Jurisdiction; Waiver of Jury Trial. The jurisdiction and waiver of right to trial by jury provisions in Section 10.12 and Section 10.15, respectively, of the Credit Agreement are incorporated herein by reference mutatis mutandis.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, each of the undersigned has caused its duly authorized officer to execute and deliver this Amendment as of the date first set forth above.

PACIFIC GAS AND ELECTRIC COMPANY,

as the Borrower

By:    /s/ Mari Becker

Name:    Mari Becker

Title:    Vice President and Treasurer

Signature Page to Amendment No. 1
Pacific Gas and Electric Company

BANK OF AMERICA, N.A.,

as Administrative Agent

By: /s/ Jacqueline G. Margetis

Name: Jacqueline G. Margetis    

Title: Director    

Signature Page to Amendment No. 1
Pacific Gas and Electric Company

BANK OF AMERICA, N.A.,

as a Lender

By: /s/ Jacqueline G. Margetis

Name: Jacqueline G. Margetis    

Title: Director

Signature Page to Amendment No. 1
Pacific Gas and Electric Company

EX-10.66

EXHIBIT 10.66

CONSENT TO RECOUPMENT OF EXCESS PERFORMANCE SHARE UNITS

This Consent to the Recoupment of Excess Performance Share Units (this “Consent”) is entered into by and between PG&E Corporation (the “Corporation”) and _______________ (the “Participant”) on _________________.

WHEREAS, the Corporation has adopted a 2014 Long-Term Incentive Plan, as amended, and a 2021 Long-Term Incentive Plan (collectively, the “Plan”), pursuant to which the Corporation may grant Performance Share Units (as such term is defined in the Plan) (“PSUs”), including Performance Share Units with performance measures based on total shareholder return (“TSR-PSUs”);

WHEREAS, upon the grant of PSUs under the Plan, the Corporation entered into a Performance Share Unit Agreement with the Participant, dated March 1, 2021 (the “2021 PSU Agreement”), to grant the Participant TSR-PSUs, subject to certain terms and conditions, and a Performance Share Unit Agreement with the Participant, dated March 01,2022 (the “2022 PSU Agreement”), to grant the Participant TSR-PSUs, subject to certain terms and conditions;

WHEREAS, the Corporation has determined that the 2021 PSU Agreement overstated that number of authorized TSR-PSUs and the 2022 PSU Agreement understated the number of authorized TSR-PSUs using a share price estimate based upon the valuation model approved by the Corporation;

WHEREAS, the Corporation wants to offer the Participant the opportunity to retain
__________ 2022 TSR-PSUs authorized by the Corporation (the “Additional 2022 TSR-PSUs”) in addition to the __________ TSR-PSUs reflected in the 2022 PSU Agreement, resulting in a new total of ___________ 2022 TSR-PSUs, subject to the terms and conditions of a new 2022 PSU Agreement, in consideration for the consent of the Participant to the recoupment of _______ TSR-PSUs reflected in the 2021 PSU Agreement but not authorized by the Corporation (the “Excess 2021 TSR-PSUs”), resulting in a new total of 2021 TSR-PSUs; and

WHEREAS, if the Participant consents to the recoupment of excess 2021 TSR-PSUs, the Corporation wishes to cancel the 2022 PSU Agreement and replace it with a new 2022 PSU Agreement that takes into account the Additional 2022 TSR-PSUs.

NOW, THEREFORE, the Participant and the Corporation, intending to be legally bound, hereby agree as follows:

1.    The Excess 2021 TSR-PSUs be, and they hereby are, cancelled, recouped and rescinded;

2.    Thereafter, the 2021 PSU Agreement shall be null and void and of no effect with respect to such Excess 2021 TSR-PSUs, and the Participant shall have no right, interest or claim under such 2021 PSU Agreement with respect to such Excess 2021 TSR-PSUs;

3.    The Participant acknowledges that the Participant has accrued no right to benefits under the terms of the 2021 PSU Agreement with respect to such Excess 2021 TSR-PSUs;

4.    The Participant acknowledges that the promise of the Corporation to permit the Participant to retain the Additional 2022 TSR-PSUs, subject to the terms and conditions of the new 2022 PSU Agreement, constitutes good and valuable consideration for the Participant’s consent to the recoupment of the Excess 2021 TSR-PSUs;

5.    This Agreement supersedes any prior agreements representations or promises of any kind and constitutes the full, complete and exclusive agreement between the Corporation and the Participant with respect to the subject matter herein;

6.    The Participant fully, finally and forever releases, discharges and covenants not to sue, and otherwise agrees not to enforce any claim, cause of action, right, title or interest against, the Corporation and its affiliates, successors and assigns, and their respective past and present directors, officers and employees (collectively, the “Releasees”) of, from and with respect to any and all claims, demands, covenants, actions, causes of action, fees, costs, sanctions, judgments, obligations, contracts,

1

agreements, debts and liabilities whatsoever, whether known or unknown, suspected or unsuspected, both at law and in equity, whether sounding in tort, intentional tort, contract, fraud, concealment, breach of statute, or conspiracy, whether or not concealed or hidden, which the Participant now has, ever had or may in the future have against the Releasees, by reason of any act or omission, in conduct or word, from the beginning of time up to and including the effective date of this Consent, on account of, arising out of or relating in any way to the TSR-PSUs; provided, however, that the Participant is not hereby releasing or discharging and does not hereby release or discharge any claims, demands, obligations, rights, liabilities or causes of action, if any, to retain the Additional 2022 TSR-PSUs in accordance with the terms of this Consent and the new 2022 PSU Agreement; and

7.    The Participant represents that he or she is not aware of any claims against the Releasees other than the claims that are released by this Consent. The Participant acknowledges that he or she has been provided the opportunity to be advised by legal counsel and is familiar with the provisions of California Civil Code § 1542, which provides as follows:

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

The Participant, being aware of said code section, agrees to expressly waive any rights he or she may have thereunder, as well as under any statute or common law principles of similar effect.

8.    This Consent may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one instrument

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

PARTICIPANT	PG&E CORPORATION
By:	By:
Name:	Name:
	Title:

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EX-10.67

EXHIBIT 10.67

CONSENT TO RECOUPMENT OF EXCESS PERFORMANCE SHARE UNITS

This Consent to the Recoupment of Excess Performance Share Units (this “Consent”) is entered into by and between PG&E Corporation (the “Corporation”) and John R Simon (the “Participant”) on October 14, 2022.

WHEREAS, the Corporation has adopted a 2014 Long-Term Incentive Plan, as amended, and a 2021 Long-Term Incentive Plan (collectively, the “Plan”), pursuant to which the Corporation may grant Performance Share Units (as such term is defined in the Plan) (“PSUs”), including Performance Share Units with performance measures based on total shareholder return (“TSR-PSUs”);

WHEREAS, upon the grant of PSUs under the Plan, the Corporation entered into a Performance Share Unit Agreement with the Participant, dated March 1, 2021 (the “2021 PSU Agreement”), to grant the Participant 18,176 TSR-PSUs, subject to certain terms and conditions, and a Performance Share Unit Agreement with the Participant, dated March 01,2022 (the “2022 PSU Agreement”), to grant the Participant 14,432 TSR-PSUs, subject to certain terms and conditions;

WHEREAS, the Corporation has determined that the 2021 PSU Agreement overstated that number of authorized TSR-PSUs and the 2022 PSU Agreement understated the number of authorized TSR-PSUs using a share price estimate based upon the valuation model approved by the Corporation;

WHEREAS, the Corporation wants to offer the Participant the opportunity to retain
14,432 2022 TSR-PSUs authorized by the Corporation (the “Additional 2022 TSR-PSUs”) in addition to the 4,884 TSR-PSUs reflected in the 2022 PSU Agreement, resulting in a new total of 19,316 2022 TSR-PSUs, subject to the terms and conditions of a new 2022 PSU Agreement, in consideration for the consent of the Participant to the recoupment of 5,353 TSR-PSUs reflected in the 2021 PSU Agreement but not authorized by the Corporation (the “Excess 2021 TSR-PSUs”), resulting in a new total of 12,823 2021 TSR-PSUs; and

WHEREAS, if the Participant consents to the recoupment of excess 2021 TSR-PSUs, the Corporation wishes to cancel the 2022 PSU Agreement and replace it with a new 2022 PSU Agreement that takes into account the Additional 2022 TSR-PSUs.

NOW, THEREFORE, the Participant and the Corporation, intending to be legally bound, hereby agree as follows:

1.    The Excess 2021 TSR-PSUs be, and they hereby are, cancelled, recouped and rescinded;

2.    Thereafter, the 2021 PSU Agreement shall be null and void and of no effect with respect to such Excess 2021 TSR-PSUs, and the Participant shall have no right, interest or claim under such 2021 PSU Agreement with respect to such Excess 2021 TSR-PSUs;

3.    The Participant acknowledges that the Participant has accrued no right to benefits under the terms of the 2021 PSU Agreement with respect to such Excess 2021 TSR-PSUs;

4.    The Participant acknowledges that the promise of the Corporation to permit the Participant to retain the Additional 2022 TSR-PSUs, subject to the terms and conditions of the new 2022 PSU Agreement, constitutes good and valuable consideration for the Participant’s consent to the recoupment of the Excess 2021 TSR-PSUs;

5.    This Agreement supersedes any prior agreements representations or promises of any kind and constitutes the full, complete and exclusive agreement between the Corporation and the Participant with respect to the subject matter herein;

6.    The Participant fully, finally and forever releases, discharges and covenants not to sue, and otherwise agrees not to enforce any claim, cause of action, right, title or interest against, the Corporation and its affiliates, successors and assigns, and their respective past and present directors, officers and employees (collectively, the “Releasees”) of, from and with respect to any and all claims, demands, covenants, actions, causes of action, fees, costs, sanctions, judgments, obligations, contracts, agreements, debts and liabilities whatsoever, whether known or unknown, suspected or unsuspected, both at law and in equity, whether sounding in tort, intentional tort, contract, fraud, concealment,

1

breach of statute, or conspiracy, whether or not concealed or hidden, which the Participant now has, ever had or may in the future have against the Releasees, by reason of any act or omission, in conduct or word, from the beginning of time up to and including the effective date of this Consent, on account of, arising out of or relating in any way to the TSR-PSUs; provided, however, that the Participant is not hereby releasing or discharging and does not hereby release or discharge any claims, demands, obligations, rights, liabilities or causes of action, if any, to retain the Additional 2022 TSR-PSUs in accordance with the terms of this Consent and the new 2022 PSU Agreement; and

7.    

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

The Participant, being aware of said code section, agrees to expressly waive any rights he or she may have thereunder, as well as under any statute or common law principles of similar effect.

8.    This Consent may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one instrument

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

PARTICIPANT	PG&E CORPORATION
By: /s/ JOHN R. SIMON	By: /s/ JULIUS COX
Name: John R. Simon	Name: Julius Cox
	Title: EVP, People, Shared Services, and      Supply Chain

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EX-10.68

PG&E Corpr9oartion

EXHIBIT 10.68

PG&E CORPORATION

DEFINED CONTRIBUTION EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN

Effective as of January 1, 2013 (the “Effective Date”), PG&E Corporation adopted this Plan for the benefit of a select group of management or highly compensated employees of PG&E Corporation and its Participating Subsidiaries. This Plan was further amended effective September 17, 2013, with respect to certain vesting and deferral election provisions and effective June 3, 2019 to reflect incentive structures adopted in connection with PG&E Corporation’s and Pacific Gas and Electric Company’s voluntary petition filed on January 29, 2019 pursuant to chapter 11 of title 11 of the U.S. Bankruptcy Code. This Plan was further amended effective January 1, 2022 to reflect changes to officer categorization. This Plan was further amended effective February 15, 2023 with respect to when contribution payments are made under the Plan. The Plan is an unfunded arrangement and is intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of ERISA.

Article 1 – Definitions

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

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

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

1(c)(2).

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

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

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

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

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

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

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

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

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

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

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PG&E Corpr9oartion

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

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

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

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

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

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

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

1.19    “STIP Payment” means the gross amount of an Eligible Employee’s bonus under the annual cash Short-Term Incentive Plan or other short-term or annual performance-based cash incentive plan (e.g., the 2019 Key Employee Incentive Plan)adopted and maintained each year by Company or its Participating Subsidiaries. STIP Payments shall not include amounts received by an employee after such employee ceases to be an Eligible Employee or prior to becoming an Eligible Employee. For purposes of calculating benefits under the Plan, STIP Payment shall be calculated before reduction for compensation voluntarily deferred or contributed by the Eligible Employee pursuant to all qualified or nonqualified plans of the applicable Employer, and shall be calculated to include amounts not otherwise included in the Eligible Employee’s gross income under Code Sections 125, 132, 402(e)(3), 402(h), or 403(b) pursuant to plans or arrangements established by the Employer; provided, however, that all such amounts will be included in compensation only to the extent that had there been no such plan, the amount would have been payable in cash to the Eligible Employee.

1.20    “Valuation Date” means:

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

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

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

Article 2 - Company Contributions

2.01    Company Contributions. Company will make a deemed contribution to each Eligible Employee’s Account in a percentage amount designated by the Committee, in its sole discretion, of the Eligible Employee’s Salary and STIP Payment, as soon as practicable, but no more than 30 days after such time that Salary or such STIP Payment is paid.

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PG&E Corpr9oartion

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

Article 3 - Vesting

3.01    Vesting of Company Contributions. Except as otherwise determined by the Plan Administrator in its sole discretion, and provided that the Eligible Employee has not Separated from Service (other than due to death), an Eligible Employee shall become one hundred percent (100%) vested in the Eligible Employee’s Account after completing at least three (3) cumulative years of service with any Employer(s). For this purpose, years of service shall be calculated on an elapsed-time, anniversary date of hire basis. “Years of cumulative service” shall include, without limitation, all service while an active participant in the Plan or in the SERP, including active service prior to any break in service. An Employee’s service will be deemed to continue while on approved leave of absence. If an Eligible Employee dies prior to both Separating from Service and satisfying the three-year vesting period, the Eligible Employee’s Account shall vest in full and be paid out in accordance with Section 6.05, below.

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

Article 4 – Investment Funds

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

Article 5 - Accountings

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

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

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

5.04    Valuations and Reports. The fair market value of each Eligible Employee’s Account shall be determined as of each Valuation Date. In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees’ Accounts, the Plan Administrator (in its discretion) may employ such

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PG&E Corpr9oartion

accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee’s Account. For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent.

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

Article 6 - Distributions

6.01    Distribution of Account Balances.

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

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

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

6.02    Election of Installment Payments. In lieu of the single sum payment under Section 6.01, an Eligible Employee may elect in writing, on such form or in such other manner as it may prescribe, and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in from 2 to 10 equal annual installments. Installment payments elected before September 17, 2013 will be considered separate payments for purposes of Code Section 409A. Installment payments will commence as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service (“Benefit Commencement Date”), and subsequent installments will be paid on each anniversary of the Benefit Commencement Date thereof until all installments are paid. However, if during the installment payment period after the Benefit Commencement Date the Account balance plus the Eligible Employee’s interest in all other Aggregated Plans is less than the dollar limit set forth in Code Section 402(g)(1)(B) in the aggregate, the value of the remaining installments and such other interest(s) may be accelerated by written election of the Plan Administrator and subsequently paid as a lump sum at the sole discretion of the Plan Administrator, except to the extent that would result in a violation of Code Section 409A. Notwithstanding anything in this Section 6.02 to the contrary, if the Eligible Employee’s vested Account balance on the Benefit Commencement Date is less than $50,000, and prior to September 17, 2013 the Eligible Employee elected pursuant to this Section 6.02 to receive payment in installments, then the distribution election described in this Section 6.02 shall be disregarded and the Eligible Employee’s entire vested Account balance shall be paid in a lump sum distribution as described in Section 6.01(2) above.

6.03    Timing of Elections.

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

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

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PG&E Corpr9oartion

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

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

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

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

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

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

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

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

Article 7 - Domestic Relations Orders

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PG&E Corpr9oartion

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

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

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

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

Article 8 - Tax Withholding

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

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

Article 9 - Administration of the Plan

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

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

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

Article 10 - Modification or Termination of Plan

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

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

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

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

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PG&E Corpr9oartion

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

Article 11 - General Provisions

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

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

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

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

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

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

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

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PG&E Corpr9oartion

APPENDIX A

PARTICIPATING SUBSIDIARIES

(As of January 1, 2013)

– Pacific Gas and Electric Company

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

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EX-10.70

EXHIBIT 10.70

PG&E CORPORATION
2005 SUPPLEMENTAL RETIREMENT SAVINGS PLAN

This is the controlling and definitive statement of the PG&E CORPORATION (“PG&E CORP”) 2005 Supplemental Retirement Savings Plan (the “Plan”). The Plan was amended for compliance with the final Code Section 409A regulations effective as of January 1, 2009, further amended effective July 13, 2009 and August 1, 2011 with respect to available investment options, further amended effective September 17, 2013 with respect to default investment funds and election of installment payments, further amended effective September 15, 2015 with respect to salary deferral percentages and crediting of matching contributions upon Separation from Service, further amended effective January 1, 2022 to reflect changes to officer characterization, and further amended effective February 15, 2023 with respect to when contribution payments are made under the Plan. Except as provided herein, the Plan is generally effective as of January 1, 2005, with respect to all individuals who are Eligible Employees as of such date. The Plan continues the benefit program embodied in the PG&E Corporation Supplemental Retirement Savings Plan (the “Prior Plan”). Benefits accrued under the Prior Plan continue to be payable under the Prior Plan pursuant to the terms and conditions of the Prior Plan.

1.    Purpose of the Plan. The Plan is established and is maintained for the benefit of a select group of management and highly compensated employees of PG&E CORP and its Participating Subsidiaries in order to provide such employees with certain deferred compensation benefits. The Plan is an unfunded deferred compensation plan that is intended to qualify for the exemptions provided in Sections 201, 301, and 401 of ERISA.

2.    Definitions. The following words and phrases shall have the following meanings unless a different meaning is plainly required by the context:

(a)    “Basic Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(c).

(b)    “Board of Directors” shall mean the Board of Directors of PG&E CORP, as from time to time constituted.

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

(d)    “Committee” shall mean the Compensation Committee of the Board, as it may be constituted from time to time.

(e)    “Eligible Employee” shall mean an Employee who:

(1)    Is an officer of PG&E CORP or any Participating Subsidiary with the title of Vice President, Senior Vice President, Executive Vice President, or higher; or

(2)    Is a key employee of PG&E CORP or any Participating Subsidiary and who is designated by the Plan Administrator as eligible to participate in the Plan.

(f)    “Eligible Employee’s Account” or “Account” shall mean as to any Eligible Employee, the separate account maintained on the books of the Employer in accordance with Section 6(a) in order to reflect his or her interest under the Plan. Accounts shall be centrally administered by the Plan Administrator or its designee.

(g)    “Employee” shall mean an individual who is treated in the records of an Employer as an employee of the Employer, who is not on an unpaid leave of absence, and/or who is not covered by a collective bargaining agreement; provided, however, such term shall not mean an individual who is a “leased employee” or who has entered into a written contract or agreement with an Employer which explicitly excludes such individual from participation in an Employer’s benefit plans. The provisions of this definition shall govern, whether or not it is determined that an individual otherwise meets the definition of “common law” employee.

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(h)    “Employers” shall mean PG&E CORP and the Participating Subsidiaries designated by the Employee Benefit Committee of PG&E CORP. An initial list of the Employers is contained in Appendix A to this Plan.

(i)    “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. Reference to a specific section of ERISA shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.

(j)    “Investment Funds” shall mean the investment funds established by the Board of Directors and reflected from time to time on Appendix B. The Investment Funds shall be used for tracking phantom investment results under the Plan.

(k)    “Matching Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(b).

(l)    “Participating Subsidiary” shall mean a United States-based subsidiary of PG&E CORP, which has been designated by the Employee Benefit Committee of PG&E CORP as a Participating Subsidiary under this Plan and which has agreed to make payments or reimbursements with respect to its Eligible Employees pursuant to Section 14(d). At such times and under such conditions as the Employee Benefit Committee may direct, one or more other subsidiaries of PG&E CORP may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.

(m)    “PG&E CORP” shall mean PG&E Corporation, a California corporation.

(n)    “Plan” shall mean the PG&E Corporation 2005 Supplemental Retirement Savings Plan, as set forth in this instrument and as heretofore and hereafter amended from time to time.

(o)    “Plan Year” shall mean the calendar year.

(p)    “Prior Plan” shall mean the PG&E Corporation Supplemental Retirement Savings Plan.

(q)    “Retirement” or “Retire” shall mean an Eligible Employee’s Separation from Service, provided that the Eligible Employee is at least 55 years of age and has been employed by an Employer for at least five consecutive years prior to the Separation from Service.

(r)    “RSP” shall mean, with respect to any Eligible Employee, the PG&E Corporation Retirement Savings Plan or any predecessor qualified retirement plan sponsored by PG&E CORP or any of its subsidiary companies.

(s)    “Separation from Service” shall mean an Eligible Employee’s “separation from service” within the meaning of Code Section 409A(a)(2)(A)(i) and related Treasury Regulations and other guidance, as determined by the Plan Administrator in its discretion.

(t)    “Valuation Date” shall mean:

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

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

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

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3.    Employer Contributions.

(a)    Matching Employer Contributions. Subject to the provisions of Section 13, the Eligible Employee’s Account shall be credited for each Plan Year with a Matching Employer Contribution, calculated in the manner provided in Sections 3(a)(1), (2), and (3) below:

(1)    First, an amount shall be calculated equal to the maximum matching contribution that would be made under the terms of the RSP, taking into account for such Plan Year the amount of pre-tax deferrals and after-tax contributions the Eligible Employee elected under the RSP. For purposes of this calculation, any amounts deferred under Subsection 4(a) of this Plan shall be treated as pre-tax deferrals under the RSP.

(2)    The calculation made in accordance with this Section 3(a)(1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(m), 401(a)(17), or 415.

(3)    The Employer Matching Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(a)(1) and (2) above, reduced by the amount of matching contribution made to such Eligible Employee’s account for such Plan Year under the RSP.

(b)    Crediting of Matching Employer Contributions. Matching Employer Contributions shall be calculated and credited to the Eligible Employee’s Account as of the first business day of February of the calendar year following the Plan Year and shall be credited only if the Eligible Employee was an Eligible Employee on at least one day of the Plan Year for which the amounts are credited, except that if an Eligible Employee Separates from Service on or after September 15, 2015, then upon that Eligible Employee’s Separation from Service, the value of the Matching Employer Contribution for the Plan Year during which Separation from Service occurs shall instead be calculated and credited to the Eligible Employee’s Account as soon as practicable, as determined by PG&E CORP. All such amounts shall be deemed to be invested in an Investment Fund designated by the Plan Administrator.

(c)    Basic Employer Contributions. Subject to the provisions of Section 13, the Account of each Eligible Employee shall be credited for each Plan Year with a Basic Employer Contribution, calculated in the manner provided in Sections 3(c)(1), (2), and (3) below:

(1)    First, an amount shall be calculated equal to the Basic Employer Contribution that would be made under the terms of the RSP, taking into account for such Plan Year the Eligible Employee’s Covered Compensation under the RSP, before any deductions for compensation deferrals elected by such Eligible Employee under Subsection 4(a) of this Plan. For Eligible Employees as defined by Section 2(e)(1) of this Plan, compensation shall also reflect such Eligible Employee’s Short-Term Incentive Plan awards.

(2)    The calculation made in accordance with this Section 3(c)(1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(a)(4), 401(a)(17), or 415.

(3)    The Employer Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(c)(1) and (2) above, reduced by the amount of Basic Employer Contributions made to such Eligible Employee’s account for such Plan Year under the RSP.

(d)    Crediting of Basic Employer Contributions. The Employer Contribution attributable to an Eligible Employee’s Short Term Incentive Plan award shall be credited to an Eligible Employee’s Account as of the first business day of the month following the date on which the Short-Term Incentive Plan award is paid. All other Employer Contributions made in respect of an Eligible Employee shall be credited to the Eligible Employee’s Account as of the first business day of February of the calendar year following the Plan Year and shall be credited only if the Eligible Employee is an Employee on the last day of the Plan Year for which the amounts are credited . All such amounts shall be deemed to be invested in an Investment Fund designated by the Plan Administrator.

(e)    FICA Taxes. Each Eligible Employee shall be responsible for FICA taxes on amounts credited to his or her Account under Sections 3 and 4(d).

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4.    Eligible Employee Deferrals.

(a)    Amount of Deferral. An Eligible Employee may defer all or part of his or her annual salary, Short Term Incentive Plan awards, Long-Term Incentive Plan (LTIP) awards (other than stock options), Perquisite Allowances, and any other special payments, awards, or bonuses as authorized by the Plan Administrator.

(b)    Credits to Accounts. Salary deferrals shall be credited to an Eligible Employee’s Account as of each payroll period. All other deferrals attributable to allowances, awards, bonuses, and other payments shall be credited as soon as practicable, but no more than 30 days after the date that they otherwise would have been paid.

(c)    Deferral Election. An Eligible Employee must file an election form with the Plan Administrator which indicates the percentage of salary and the amount of any awards, allowances, payments, and bonuses to be deferred under the Plan. The election shall occur no later than December 31 (or such earlier date established by the Plan Administrator) of the calendar year next preceding the service year (within the meaning of Treasury Regulation Section 1.409A-2(a)(3)). Notwithstanding the foregoing, to the extent permitted under Treasury Regulation Section 1.409A-2(a)(7), upon first becoming an Eligible Employee, an election to defer shall be effective for compensation to be earned for services performed beginning in the month following the filing of a Deferral Election Form, provided said Form is filed within 30 days following the date when the employee first becomes an Eligible Employee. Notwithstanding the foregoing, in the case of performance-based compensation (within the meaning of Treasury Regulation Section 1.409A-1(e)), the election may be made with respect to such performance-based compensation on or before the date that is six months before the end of the applicable performance period to the extent permitted under Treasury Regulation Section 1.409A-2(a)(8). The Plan Administrator may, in its sole discretion, permit elections to be made under other timing rules that comply with Code Section 409A.

(d)    Deferral of Special Incentive Stock Ownership Premiums. All of an Eligible Employee’s Special Incentive Stock Ownership Premiums are automatically deferred to the Plan immediately upon grant and converted into units in the PG&E Corporation Phantom Stock Fund. The units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon remain unvested until the earlier of the third anniversary of the date on which the Special Incentive Stock Ownership Premiums are credited to an Eligible Employee’s account (provided the Eligible Employee continues to be employed on such date), death, disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code), or Retirement of the participant, or upon a Change in Control (as defined in the LTIP). Unvested units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon shall be forfeited upon termination of the Eligible Employee’s employment (unless otherwise provided in the PG&E Corporation Executive Stock Ownership Program or the PG&E Corporation Officer Severance Plan) or if an Eligible Employee’s stock ownership falls below the levels set forth in the Executive Stock Ownership Program.

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

6.    Accounting.

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

(b)    Investment Earnings. Each Eligible Employee’s Account shall initially reflect the value of his or her Account’s interest in each of the Investment Funds, deemed acquired with the amounts credited thereto. Each

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Eligible Employee’s Account shall also be credited (or debited) with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account. Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee’s Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee’s Account.

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

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

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

7.    Distributions.

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

    In the case of an Alternate Payee (as defined in Section 9(a), to the extent allowable under Code Section 409A, distribution shall be made as directed in a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 9(a), but only as to the portion of the Eligible Employee’s Account which the DRO states is payable to the Alternate Payee.

(b)    Specific Distributions. In lieu of a payment described in Section 7(a), by filing an irrevocable election with the Plan Administrator, an Eligible Employee may at the time of deferral elect to receive distribution of the specific type of income deferral for that calendar year plus the earnings thereon (exclusive of Special Incentive Stock Ownership Premiums) in, or in the case of installments commencing in, January of any future year and in the form of either (1) a single lump sum or (2) from two to ten annual installments with subsequent installments paid on each anniversary of the installment commencement date.

(c)    Election of Installment Payments. In lieu of a single sum payment under Section 7(a), except in the case of Special Incentive Stock Ownership Premiums, an Eligible Employee may elect in writing to the Plan Administrator, on such form or in such other manner as it may prescribe, and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in from 2 to 10 equal annual installments. If the Eligible Employee elects installment payments pursuant to this Section 7(c), then such installment payments shall commence as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service (“Benefit Commencement Date”) and subsequent installments will be paid on each anniversary of the Benefit Commencement Date thereof until all installments are paid.

(d)    Change in Distribution Election. An Eligible Employee may change a distribution election previously made pursuant to Section 7(b) or 7(c) (or in place by default pursuant to Section 7(a)) only with respect to the portion of the Eligible Employee’s Account attributable to Eligible Employee Deferrals (exclusive of Special Incentive Stock Ownership Premiums) and only in accordance with the rules under Code Section 409A. Generally, a subsequent election pursuant to this Section 7(d): (1) cannot take effect for twelve (12) months, (2) must occur at least twelve (12) months before the first scheduled payment under a payment at a specified date elected pursuant to Section 7(b), and (3) must defer a previously elected distribution at least five (5) additional years. The Plan Administrator may establish additional rules or restrictions on changes in distribution elections.

(e)    Death Distributions. If an Eligible Employee dies before the balance of his or her Account has been distributed (whether or not the Eligible Employee had previously had a Separation from Service), the Eligible Employee’s Account shall be distributed in a lump sum to the beneficiary designated or otherwise determined in

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accordance with Section 7, as soon as practicable after the date of death (but in any event within 90 days after the date of death).

(f)    Special Incentive Stock Ownership Premiums. Distributions attributable to Special Incentive Stock Ownership Premiums shall only be made in the form of one or more certificates for the number of vested Special Incentive Stock Ownership Premium units, rounded down to the nearest whole share, in accordance with the timing rule set forth in Section 7(a).

(g)    Effect of Change in Eligible Employee Status. If an Eligible Employee ceases to be an Eligible Employee but does not experience a Separation from Service, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 7.

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

(i)    Beneficiary Designations. Each Eligible Employee may designate, in a signed writing delivered to the Plan Administrator, on such form as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee’s death. An Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner. Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation received by the Plan Administrator shall supersede all prior designations. If an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives the Eligible Employee, the Eligible Employee’s Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under the RSP.

(j)    Undistributable Accounts. Each Eligible Employee and (in the event of death) his or her beneficiary shall keep the Plan Administrator advised of his or her current address. If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee’s Account is payable under this Section 7, the Eligible Employee’s Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 7, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto. PG&E CORP shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee’s former Employer (or any successor thereto).

    (k)    Plan Administrator Discretion. Within the specific time periods described in this Section 7, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan.

8.    Distribution Due to Unforeseeable Emergency (Hardship Distribution). A participant may request a distribution due to an unforeseeable emergency (within the meaning of Code Section 409A) by submitting a written request to the Plan Administrator. The Plan Administrator shall have the authority to require such evidence as it deems necessary to determine if a distribution is warranted. If an application for a hardship distribution due to an unforeseeable emergency is approved, the distribution shall be payable in a lump sum within 30 days after approval of such distribution. After receipt of a payment requested due to an unforeseeable emergency, a participant may not make additional deferrals during the remainder of the Plan Year in which the recipient received the payment. The distribution due to an unforeseeable emergency shall not exceed the amount reasonably necessary to meet the emergency. This Section 8 shall be administered in accordance with the requirements of Code Section 409A.

9.    Domestic Relations Orders.

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

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

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

(3)    Hold Procedures. Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee’s Account for a reasonable period of time (as determined by the Plan Administrator in accordance with Code Section 409A) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee’s Account is a source of the payment under such domestic relations order. For purposes of this Section 9(a)(3), a “hold” means that no withdrawals, distributions, or investment transfers may be made with respect to an Eligible Employee’s Account. If the Plan Administrator places a hold upon an Eligible Employee’s Account pursuant to this Section 9(a)(3), it shall inform the Eligible Employee of such fact.

10.    Vesting. Except as provided in Section 4(d), an Eligible Employee’s interest in his or her Account at all times shall be 100 percent vested and nonforfeitable.

11.    Administration of the Plan.

(a)    Plan Administrator. The Employee Benefit Committee of PG&E CORP is hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the Senior Human Resource Officer for PG&E CORP, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan. The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan.

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

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

12.    Funding. All amounts credited to an Eligible Employee’s Account under the Plan shall continue for all purposes to be a part of the general assets of PG&E CORP. The interest of the Eligible Employee in his or her Account, including his or her right to distribution thereof, shall be an unsecured claim against the general assets of PG&E CORP. While PG&E CORP may choose to invest a portion of its general assets in investments identical or similar to those selected by Eligible Employees for purposes of determining the amounts to be credited (or debited) to their Accounts, nothing contained in the Plan shall give any Eligible Employee or beneficiary any interest in or claim against any specific assets of PG&E CORP.

13.    Modification or Termination of Plan.

(a)    Employers’ Obligations Limited. The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan. PG&E CORP at any time may, by appropriate amendment of the Plan, suspend Matching Employer Contributions and/or Basic Employer Contributions or may discontinue Matching Employer Contributions and/or Basic Employer Contributions, with or without cause.

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

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

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(c)    Effect of Termination. If the Plan is terminated, the balances credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 7; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees’ Accounts to the extent provided in Treasury Regulation Sections 1-409A-3(j)(4)(ix) (A) (relating to terminations in connection with certain corporate dissolutions), (B) (relating to terminations in connection with certain change of control events), and (C) (relating to general terminations).

14.    General Provisions.

(a)    Inalienability. Except to the extent otherwise directed by a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 9(a)) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process.

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

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

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

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

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

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

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APPENDIX A

EMPLOYERS

(As of January 1, 2005)

– PG&E Corporation

– All Participating Subsidiaries

Participating Subsidiaries (as of January 1, 2005):

– Pacific Gas and Electric Company

– All U.S. subsidiaries of the above-named corporations

APPENDIX B

INVESTMENT FUNDS

(as of August 1, 2011)

SRSP Target Date Funds are a suite of funds that provides investors with convenient, cost-effective exposure across major global asset classes within single investment options. The suite consists of ten funds targeting a normal retirement age of 65. These broadly diversified vehicles combine low-cost stock and bond strategies and automatic rebalancing with professional judgment regarding the appropriate risk level for a specific retirement date. On an annual basis, the SRSP Target Date Funds incrementally reduce exposure to equities and increase exposure to fixed income assets as the target retirement date approaches. This equity roll down continues for five years after the target retirement date, at which time a fixed income-oriented allocation of 65% is combined with 35% stocks that is maintained indefinitely within the RSP Target Retirement Income Fund. A participant typically invests in one fund within the suite which fund reflects a target retirement date closest to the anticipated retirement date of the participant.

PG&E Corporation Phantom Stock Fund converts contributions and transferred amounts into units of phantom common stock valued at the closing price of a share of PG&E Corporation common stock on the contribution/transfer date. If the transfer request is received after the market closes, the following day’s closing price will be used. Thereafter, the value of a unit shall fluctuate depending on the price of PG&E Corporation common stock. Each time a dividend is paid on common stock, an amount equal to such dividend shall be credited to the account as additional units.

SRSP Total US Stock Index Fund seeks to match the returns of the Russell 3000 Index. The Russell 3000 Index represents the 3,000 largest stocks in the US market and accounts for approximately 97% of the US stock market’s capitalization. The strategy of investing in the same stocks as the Russell 3000 Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Large Company Stock Index Fund seeks to match the returns of the S&P 500 Index. The Fund invests in all 500 stocks in the S&P 500 Index in proportion to their weightings in the Index. The S&P 500 provides exposure to about 85% of the market value of all publicly traded common stocks in the United States. The strategy of investing in the same stocks as the S&P 500 Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Small Company Stock Index Fund seeks to match the returns of the Russell Small Cap Completeness Index. The Fund invests in all of the stocks in the Russell Special Small Cap Completeness Index in proportion to their weightings in the Index. The Russell Small Cap Completeness Index represents about 15% of the market value of all publicly traded common stocks in the United States. The strategy of investing in the same stocks as the Russell Small Cap Completeness Index provides reliable exposure to this asset class and results in lower expenses.

SRSP World Stock Index Fund seeks to match the returns of the MSCI All Country World Index over the long term. The MSCI All Country World Index invests in the US, Canada, Europe, Australasia and Far East countries and emerging markets. The strategy of investing in a portfolio of stocks designed to track the MSCI All Country World Ex-US Index provides reliable exposure to this asset class and results in lower expenses.

SRSP International Stock Index Fund seeks to match the returns of the MSCI World ex-US Index. The Fund invests in all of the stocks in the MSCI World ex-US Index in proportion to their weightings in the Index. The MSCI World ex-US index provides exposure to Canada as well as developed market countries in Europe, Australasia, and the Far East. The strategy of investing in the same stocks as the MSCI World ex-US provides reliable exposure to this asset class and results in lower expenses.

SRSP Emerging Markets Enhanced Index Fund seeks to provide a total investment return in excess of the performance of the MSCI Emerging Markets Index over the long term. The MSCI Emerging Markets Index invests in emerging market countries. The strategy attempts to identify and capitalize on inefficiencies in the emerging markets by employing a disciplined investment process that combines top-down country selection with bottom-up stock selection to determine an optimal country and security mix. Portfolio construction is risk-controlled, with the goal of a well-diversified portfolio that has characteristics similar to the benchmark and superior performance potential.

SRSP Bond Index Fund seeks to match the returns of the Barclays Capital Aggregate Bond Index. The Fund invests in a portfolio of government, corporate, mortgage-backed, and asset-backed fixed-income securities that is representative of the broad domestic bond market. The Barclays Capital Aggregate Bond Index is an unmanaged,

market-value weighted index of investment-grade, fixed-rate debt issues, including government, corporate, asset-backed, and mortgage-backed securities, with maturities of one year or more. The strategy of investing in a portfolio of bonds designed to track the Barclays Capital Aggregate Bond Index provides reliable exposure to this asset class and results in lower expenses.

SRSP US Government Bond Index Fund seeks to match the returns of the Barclays Capital US Government Bond Index. The Fund invests in a well-diversified portfolio that is representative of the Barclays Capital US Government Bond Index, which consists of US Government and government agency securities (other than mortgage securities) with maturities of one year or more. The strategy of investing in a portfolio of stocks designed to track the Barclays Capital US Government Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Money Market Investment Fund is maintained for the purpose of investing in a diversified portfolio consisting primarily of short-term government and non-government debt securities. The primary objective of this fund is to provide participants with preservation of principal.

Short-Term Bond Index Fund is maintained for the purpose of investing in a diversified portfolio consisting primarily of short-term, marketable fixed-income securities.

AA Utility Bond Fund accrues interest on the amount invested in this fund. The interest rate is equal to the AA Utility Bond Yield reported by Moody’s Investor Services.

PG&E CORPORATION

2005 SUPPLEMENTAL RETIREMENT SAVINGS PLAN

1.    Purpose of the Plan    1

2.    Definitions    1

3.    Employer Contributions    3

4.    Eligible Employee Deferrals    4

5.    Investment Funds    5

6.    Accounting    6

7.    Distributions    6

8.    Distribution Due to Unforeseeable Emergency (Hardship Distribution)    8

9.    Domestic Relations Orders    8

10.    Vesting    9

11.    Administration of the Plan    9

12.    Funding    10

13.    Modification or Termination of Plan    10

14.    General Provisions    10

EX-10.71

EXHIBIT 10.71

PG&E CORPORATION

SHORT-TERM INCENTIVE PLAN

(As adopted effective January 19, 2022)

1.    Purpose

Effective as of January 19, 2022 (the “Effective Date”), PG&E Corporation adopted this Short-Term Incentive Plan is to motivate and reward eligible officers and other employees of PG&E Corporation (or its successor) and its Participating Subsidiaries, and other designated participants, with financial incentives if they meet or exceed certain goals. The Plan was amended February 15, 2023 to reflect that, for performance periods starting on or after January 1, 2023, eligible participants must be employed on the pay-out date. The Plan is intended to be a bonus arrangement exempt from the Employee Retirement Income Security Act of 1974, as amended, and is not primarily intended to systematically defer payment until the termination of covered employment or beyond or to provide retirement income.

2.    Definitions

2.1    “Administrator” means the Committee.

2.2    “Award” means an award to a Participant with respect to a Performance Period granted under the Plan.

2.3    “Board” means the Board of Directors of PG&E Corporation.

2.4    “Clawback Policy” means the Corporation’s and the Utility’s Executive Incentive Compensation Recoupment Policy, as may be amended from time to time.

2.5    “Committee” means the People and Compensation Committee of the Board, as constituted from time to time.

2.6    “Corporation” means PG&E Corporation, or its successor.

2.7    “Group” means theCorporation and its Participating Subsidiaries.

2.8    “Participant” means any employee of the Group who (a) is considered an “officer” with respect to the Corporation or the Utility under Section 16 of the Securities Exchange Act of 1934, as amended from time to time, or who otherwise is an officer whose compensation is established and/or recommended by the Committee, (b) is employed in a job classification not included in a unit represented by a certified labor organization, (c) is employed in a union-represented job classification that is eligible to participate in the STIP as defined in the applicable collective bargaining agreements, or (d) otherwise is recommended by the Corporation Chief Executive Officer as a participant in the Plan.

2.9    “Participating Subsidiaries” means Pacific Gas and Electric Company, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., or such other company, affiliate, subsidiary, or association as may be designated by the Committee.

2.10    “Performance Goal” means a target to be attained with respect to one or more performance criteria, which target may be expressed as a formula or a standard or otherwise, established by the Administrator (in its sole discretion) for a Performance Period. The performance criteria may relate to, without limitation, one or more of the following objective or relative indicators of safety, operational, or financial performance with respect to one or more Group members, a division or unit of one or more Group members, or the Participant, as determined by the Administrator: (i) sales revenue; (ii) gross margin; (iii) operating margin; (iv) operating income; (v) pre-tax profit; (vi) earnings before interest, taxes and depreciation and amortization (EBITDA)/adjusted EBITDA; (vii) net income; (viii) expenses; (ix) the market price of the Stock; (x) earnings per share; (xi) return on shareholder equity or assets; (xii) return on capital; (xiii) return on net assets; (xiv) economic profit or economic value added (EVA); (xv) market share; (xvi) customer service or customer satisfaction; (xvii) safety; (xviii) total shareholder return; (xix) earnings; (xx) cash flow; (xxi) revenue; (xxii) profits before interest and taxes; (xxiii) profit/loss; (xxiv) profit margin;

(xxv) working capital; (xxvi) price/earnings ratio; (xxvii) debt or debt-to-equity; (xxviii) accounts receivable; (xxix) write-offs; (xxx) cash; (xxxi) assets; (xxxii) liquidity; (xxxiii) earnings from operations; (xxxiv) operational reliability; (xxxv) environmental performance; (xxxvi) funds from operations; (xxxvii) adjusted revenues; (xxxviii) free cash flow; (xxxix) core earnings/earnings per share; (xxxx) operational performance; (xxxxi) ESG (environment, social, and governance); (xxxxii) DEI (diversity, equity, and inclusion); or (xxxxiii) security (including but not limited to infrastructure and cybersecurity).

Performance Goals may include a minimum, maximum, target level and intermediate levels of performance, with the final value of an Award determined under the applicable formula by the level attained during the applicable Performance Period, subject to any adjustments that the Administrator may decide to apply in its discretion. A Performance Goal may be stated as an absolute value or as a value determined relative to a standard selected by the Committee.

2.11    “Performance Period” means any period as determined by the Administrator, in its sole discretion, over which a Performance Goal is measured. The Administrator may establish different Performance Periods for different Participants.

2.12    “Plan” means this Short-Term Incentive Plan, as amended from time to time.

2.13    “Retire” means to resign from employment with the Group and to be at least 55 years of age on the date of resignation.

2.14    “Section 409A” means Section 409A of the Internal Revenue Code of 1986, as amended.

3.    Administration of the Plan

The Plan shall be administered by the Administrator, who will have the discretionary authority to do the following, in its sole discretion, but subject to applicable laws and requirements established by the Board.:

(a)     determine the persons to whom, and the time or times at which, Awards shall be granted and the size of each Award;

(b)    to determine the terms, conditions and restrictions applicable to each Award (which need not be identical), including, without limitation, (i) the size of each Award, (ii) the Performance Period, (iii) the Performance Goals applicable to any Award and the extent to which such Performance Goals have been attained, (iv) the effect of the Participant’s termination of employment on any of the foregoing, and (v) all other terms, conditions and restrictions applicable to any Award or shares acquired pursuant thereto not inconsistent with the terms of the Plan;

(c)    to amend the terms of any Award or to waive any restrictions or conditions applicable to any Award;

(d)    to prescribe, amend or rescind additional guidelines and terms relating to the Plan, including, without limitation, the terms of the annual Award program;

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

(f)    to delegate to the Corporation Chief Executive Officer or the most senior Corporation officer responsible for Human Resources the authority with respect to ministerial matters regarding the Plan and Awards made under the Plan.

The decisions of the Administrator shall be final and binding on all parties making claims under the Plan. The Administrator, in its sole discretion, may delegate this administrative authority with respect to Participants who are not officers or other persons whose transactions in Company stock are subject to Section 16 of the Securities Exchange Act of 1934, as amended, to the Corporation Chief Executive Officer or the most senior Corporation officer responsible for Human Resources, subject to applicable laws and requirements established by the Board.

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4.    Eligibility and Participation

Any individual who is a Participant on the first day of the relevant Performance Period or, if later, the first day of employment with the Group as a Participant, shall be eligible to participate in the Plan, and shall participate in the Plan as determined at the sole discretion of the Administrator (or appropriate delegate).

5.    Amount of Awards

5.1    With respect to each Participant, the Administrator (or appropriate delegate, and subject to applicable laws and requirements established by the Board) shall establish and communicate in writing one or more Performance Periods and one or more Performance Goals (including, if applicable and without limitation, threshold, target, and maximum Performance Goals, as well as individual modifiers).

5.2    The amount of each Award shall be determined by the Administrator (or appropriate delegate, and subject to applicable laws and requirements established by the Board) based on the extent to which the Performance Goals have been met.

5.3    The Administrator (or appropriate delegate, and subject to applicable laws and requirements established by the Board) reserves the right, in its sole discretion, to adjust, upward or downward, including to $0, the amount of an Award otherwise payable to a Participant with respect to any Performance Period, including adjusting the amount to reflect individual performance.

6.    Payment of Awards

6.1    Unless otherwise determined by the Administrator (or appropriate delegate) and except as otherwise set forth in Section 6.2 below, in order to receive payment of an Award, a Participant must have been employed by the Group at the end of the associated Performance Period. For Performance Periods starting on or after January 1, 2023, unless otherwise determined by the Administrator (or appropriate delegate) and except as otherwise set forth in Section 6.2 below, in order to receive payment of an Award, a Participant must be employed by the Group on the pay-out date.

6.2    Notwithstanding Section 6.1 above, and unless otherwise determined by the Administrator (or appropriate delegate) and subject to Section 8:

(a)    If a Participant Retires during a Performance Period, that Participant will remain eligible for a pro-rated associated Award payment based on the portion of that Performance Period during which the Participant was employed, based on Administrator (or appropriate delegate) approval of the Plan and Award, actual corporate performance, and achievement of the Performance Goals through the end of the applicable Performance Period.

(b)    Unless otherwise set forth in an applicable formal severance plan, policy, program, or agreement if a Participant who has been employed by the Group for at least six (6) months of the Performance Period is involuntarily terminated from employment with the Group during such Performance Period pursuant to a formal severance plan, policy, or program, such as a targeted voluntary severance program, or as a termination other than for cause (or term of similar import) under a severance policy or agreement, that Participant will remain eligible for a pro-rated associated Award payment based on the portion of that Performance Period during which the Participant was employed, based on Administrator (or appropriate delegate) approval of the Plan and Award, actual corporate performance, and achievement of the Performance Goals through the end of the applicable Performance Period.

(c)    If a Participant’s employment is terminated due to death or disability during a Performance Period, then the Participant or the Participant’s estate or legal representative, as applicable, will be eligible for a pro-rated associated Award payment based on the portion of the Performance Period during which the Participant was employed, based on Administrator (or appropriate delegate) approval of the Plan and Award, actual corporate performance, and achievement of the Performance Goals through the end of the applicable Performance period.

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Any payment pursuant to this Section 6.2 will be made when payments under the Plan are otherwise made to Participants.

6.3    It is intended that participation in the Plan will not give rise to a “legally binding right” (within the meaning of Section 409A) to compensation and will, therefore, be exempt from the application of Section 409A. To the extent not so exempt, payments under the Plan shall be made within two months and 15 days following the end of the calendar year in which such payments cease to be subject to a “substantial risk of forfeiture,” within the meaning of Section 409A. In the event that the Corporation’s taxable year ceases to be the calendar year, then payments under the Plan shall be made within two months and 15 days following the later of the end of the calendar year or the Corporation’s taxable year in which such payments cease to be subject to a “substantial risk of forfeiture,” within the meaning of Section 409A.

6.4    Notwithstanding any other provision of the Plan to the contrary, any payment hereunder shall be subject to potential cancellation, recovery, repayment, or other action in accordance with the terms of any Clawback Policy. By accepting an Award, the relevant Participant agrees and consents to the enforcement and implementation of the Clawback Policy without further consent or action being required of the Participant.

7.    General

7.1    Tax Withholding. Payments under the Plan are subject to deduction for any federal, state, or local income and payroll taxes required by law to be withheld with respect to such payments. The Group also may withhold from any other amount payable hereunder to the Participant an amount equal to the taxes required to be withheld with respect to any payment under the Plan.

7.2    Claim to Awards and Employment Rights. Nothing in the Plan shall confer upon any Participant the right to continued employment with the Group, or affect in any way the right of any member of the Group to terminate the Participant’s employment at any time and for any reason, or to change the Participant’s responsibilities. Awards represent unfunded and unsecured obligations of the Group, and a holder of any right hereunder in respect of any Award shall have no rights other than those of a general unsecured creditor to the Group.

7.3    Nontransferability. A person’s rights and interests under the Plan, including any Award previously made to such person or any amounts payable under the Plan, may not be assigned, pledged, or transferred except, in the event of a Participant’s death, by will, trust or the laws of descent and distribution, or by court order.

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

7.5    Expenses. The costs and expenses of administering the Plan shall be borne by participating companies in the Group, and may be equitably apportioned by the Administrator among companies within the Group. Each company whose officers or other employees are granted awards under the Plan shall be responsible for making payments pursuant to the Plan on behalf of Participants employed by that company, or for reimbursing the Corporation for the cost of such payments, as determined by the Corporation in its sole discretion. In the event that a company fails to make payment or reimbursement and the Corporation does not exercise its discretion to make the payment on such participating company’s behalf, a Participant’s (or other payee’s) sole recourse shall be against that Participant’s employer.

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7.6    Titles and Headings. The titles and headings of the sections of the Plan are for convenience of reference only, and in the event of any conflict, the text of the Plan, rather than such titles or headings, shall control.

7.7    Governing Law. The validity, construction, and effect of the Plan, any rules and regulations relating to the Plan, and any Award shall be determined in accordance with the laws of the State of California (without giving effect to principles of conflicts of laws thereof) and applicable Federal law.

8.    Amendments, Suspension, or Termination of the Plan

The Administrator may, at any time, or from time to time, amend or suspend and, if suspended, reinstate, the Plan in whole or in part. The Administrator may terminate the Plan at any time, provided such termination shall not affect the payment of any Awards with respect to a Performance Period that was completed by the Participant prior to the date of the termination.

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EX-10.77

EXHIBIT 10.77

AMENDMENT

TO THE

POSTRETIREMENT LIFE INSURANCE PLAN OF

THE PACIFIC GAS AND ELECTRIC COMPANY

A.    Adoption and effective date of amendment. This Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (the “Plan”) is adopted by the Employee Benefit Committee of PG&E Corporation pursuant to its authority set forth in the Plan. This Amendment shall be effective as of January 1, 2020.

B.    Supersession of inconsistent provisions. This Amendment shall supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this Amendment.

C.    A new Section 3.01(c) of the Plan is added to read as follows:

(c)    Notwithstanding anything herein to the contrary, individuals who previously received a lump sum cash payment under Section 3.01(b) of the PLAN that was not coded as a “Postretirement Life Insurance Plan” payment in the payroll records of the COMPANY, and who continued to receive communications regarding a continuing PLAN benefit, may elect to purchase supplemental life insurance under the PLAN; provided that, each such individual enters into, and continues to abide by the terms of, an agreement with the EMPLOYEE BENEFIT COMMITTEE setting forth the terms of such purchase.

The foregoing amendment was duly adopted by the Employee Benefit Committee on

December 28, 2020, pursuant to the authority described above.

/s/ JOHN R. SIMON

____________________________________

John R. Simon

Chairman, Employee Benefit Committee

______12/29/2022______________________________

Date

EX-14

EXHIBIT 14

PG&E Code of Conduct Text

February 16, 2022

(Front Cover)

[Our Purpose icon]

Living our Purpose, Virtues and Stands

PG&E Code of Conduct

February 2022

[PG&E logo]

(Inside Cover left)

The most up-to-date version of this Code of Conduct can be found online at http://www.pgecorp.com/corp/about-us/corporate-governance/corporation-policies/employee-conduct.page

For questions or guidance on the PG&E Code of Conduct, contact the Ethics & Compliance Helpline at 1-888-231-2310, www.pgecorp.ethicspoint.com or EthicsComplianceHelp@pge.com.

In the Code of Conduct, the term “PG&E” refers to PG&E Corporation and its affiliates and subsidiaries, including Pacific Gas and Electric Company. The term “coworkers” refers to PG&E employees and the term “suppliers” refers to an individual or organization that does or is actively seeking to do business with PG&E.

The conduct, conflict of interest and compliance standards in this Code apply to all coworkers and officers of PG&E. PG&E board members should reference the Director Code of Conduct. Suppliers, including contractors, should reference the PG&E Supplier Code of Conduct.

(Inside Cover right)

Welcome to the PG&E Code of Conduct

(Table of Contents)

TABLE OF CONTENTS

01 Foreword

02 PG&E Code of Conduct: Your guide to ethics and compliance

03 Our Ethical Commitments

04 Speak Up, Listen Up, Follow Up

05 Building Trust with Each Other

06 Building Trust with Our Business Contacts

07 Building Trust with Our Communities and Customers

08 Building Trust with Governments

(Section 01)

Our Purpose, Virtues and Stands form the foundation for our standards of ethics and compliance. The PG&E Code of Conduct outlines the expectations for how we work.

Section 01

Foreword

A MESSAGE FROM PATTI POPPE

PG&E Team, 

Our Purpose at PG&E is delivering for our hometowns, serving our planet and leading with love. That’s our responsibility, both as a team and as individuals. 

Fulfilling our Purpose requires a personal commitment to living our Virtues every day. We will show our Virtue of being trustworthy by doing our work the right way and with integrity every time.  

Our PG&E Code of Conduct outlines the expectations for how we work. I ask that you take time to read it and understand it. More than that, let’s practice it every day by following both the letter and spirit of our Code of Conduct and all compliance requirements. Together, we can make it enjoyable to work with and for PG&E. 

As part of our Virtue of being curious, we ask questions and notice when something doesn’t seem right. If you ever have concerns about safety or possible misconduct, talk to your leader immediately or contact any of the resources listed on the Code of Conduct mobile app or intranet page. 

I want each of you to feel safe and supported, especially when speaking up about your ideas and concerns. PG&E’s leadership team will listen up and follow up by taking action on what you share. It’s also important for you to know that PG&E does not tolerate retaliation for speaking up or participating in an investigation.  

Join me in taking personal ownership of our PG&E Code of Conduct and showing our coworkers, customers and communities that we are worthy of their trust. 

Leading with Love, 

Patti Poppe 

Chief Executive Officer 

PG&E Corporation 

See Patti’s video

Join me in taking personal ownership of our PG&E Code of Conduct and showing our coworkers, customers and communities that we are worthy of their trust.

(Section 02)

Adhering to our Code of Conduct is critical to carrying out our Purpose, being true to our Virtues, and accomplishing our Stands.

Section 02

PG&E Code of Conduct

Your guide to ethics and compliance

Our Code of Conduct illustrates how we live our Purpose, Virtues and Stands. It reflects who we are. Adhering to our Code of Conduct is critical to carrying out our Purpose, being true to our Virtues and accomplishing our Stands. This document guides our overarching commitment to our ethical culture and compliance.

Every PG&E coworker is responsible for complying with the Code, laws and regulations, in all actions. The Code of Conduct is divided into sections that address:

Our ethical commitments

Speak up, listen up, follow up

Building trust with various stakeholders: with each other, with our business contacts, with our customers and communities, and with government entities

PG&E does not grant waivers to the Code of Conduct. This Code of Conduct is an addition to, and not a replacement of, regulatory and legal policies. In a dynamic and fluid business climate, it’s not possible to predict every conceivable situation; so whenever possible, check the online version of the Code of Conduct for the most current information.

(Section 03)

We take personal responsibility for speaking up, listening up and following up.

Section 03

Our Ethical Commitments

How we do our work matters. We live our Virtues and conduct ourselves in an honest and ethical manner.

ADHERING TO THE CODE OF CONDUCT

How we do our work matters. We live our Virtues and conduct ourselves in an honest and ethical manner. By adhering to the Code of Conduct, complying with all laws, rules and regulations, and PG&E’s policies, standards and procedures, we build trust with our customers, stakeholders and each other. We demonstrate ownership by:

Speaking up, listening up and following up

Complying with applicable laws, regulations, our Code and PG&E requirements

Raising questions and concerns if we become aware of possible violations of laws, regulations, our Code or PG&E requirements

Cooperating fully when responding to an investigation or audit

Working and communicating respectfully with everyone

Responsibilities of PG&E Leaders

When in a leadership position, we own additional responsibilities for ethics and compliance, including:

Building trust and creating an environment that makes it safe for coworkers to speak up to share ideas and concerns

Recognizing and meeting our commitments with the appropriate degree of urgency

Encouraging coworkers to raise issues

Not engaging in retaliation against those who raise issues about safety, violations of laws or regulations, or this Code of Conduct

Listening up and following up with coworkers who speak up

Openly acknowledging when we are wrong or don’t know the answer, and seeking guidance if unsure of the appropriate course of action

Escalating and reporting suspected violations of this Code, whether by coworkers or PG&E’s suppliers or business partners, to the Ethics & Compliance Helpline

Being an ethical role model—making ethics and compliance a cornerstone of our work

Making personnel decisions based on merit and performance

AS A PG&E LEADER—

I will comply with this Code of Conduct and other relevant PG&E policies and standards.

I won’t direct my coworkers to violate this Code, a law, a regulation or a PG&E policy or procedure.

I will listen to and follow up with coworkers who raise concerns and escalate appropriately.

I will promptly report suspected violations of this Code to the Ethics & Compliance Helpline when brought to my attention.

I won’t retaliate.

I won’t threaten retaliation.

I won’t tolerate retaliation if I observe it against another coworker.

AS A PG&E COWORKER—

I will comply with the laws, regulations and PG&E requirements that apply to my job.

I will act with integrity at all times.

I will speak up promptly about possible misconduct, safety issues or new ideas.

I won’t retaliate.

I won’t threaten retaliation.

AS A PG&E LEADER—I won’t direct my coworkers to violate this Code, a law, a regulation or a PG&E policy or procedure.

AS A PG&E COWORKER—I will comply with the laws, regulations and PG&E requirements that apply to my job.

MAKING ETHICAL DECISIONS

When faced with an ethical dilemma, ask yourself:

Have I made sure that my actions will not impact anyone’s safety?

Is it legal?

Does it feel right?

Do I act respectfully and with integrity, and in such a way that if my words or actions were to be made public, I wouldn’t feel embarrassed or lose the trust of customers, stakeholders or coworkers?

Is it consistent with our Code, our Virtues and our policies?

Am I willing to be held accountable for my actions?

Yes

If you answered “yes” to every question, proceed.

No

If you’re not sure, or you answered “no” to any of the questions, don’t proceed.

Ask your leader or the Ethics & Compliance Helpline for guidance. For more information see the How You Can Speak Up section.

Coworkers who don’t comply with this Code or other PG&E policies, standards or procedures may face disciplinary action or termination of employment. Leaders should contact their HR representative for help determining the appropriate course of action if a coworker violates the Code of Conduct.

If a safety incident occurs, our primary objective is to learn why it happened and take the necessary steps to put controls in place to prevent recurrence. Disciplinary action will be considered only if a coworker has acted recklessly, has a pattern of carelessness or noncompliance, or intentionally violates safety rules or other PG&E policies.

PG&E does not tolerate discipline or retaliation against a coworker for speaking up and raising a safety concern. When you speak up for safety, you are doing the right thing. Speaking up helps to reduce both the frequency and severity of safety incidents.

AS A PG&E COWORKER—I won’t retaliate or threaten retaliation.

(Section 04)

PG&Eis a safer, better enterprise when we speak up, listen up and follow up.

Section 04

Speak Up, Listen Up, Follow Up

When we know about a problem, we can fix it.

SPEAK UP: HOW TO DO IT AND WHY IT MATTERS

At PG&E, we’re committed to fostering a workplace where everyone feels safe to ask for guidance, share ideas or raise concerns—and one where everyone is confident that those concerns will be heard and taken seriously. When we know about a problem, we can fix it. In short, PG&E is a safer, better enterprise when we speak up, listen up and follow up.

If you encounter activities at work that you believe may constitute misconduct, including unethical behavior, or a violation of applicable laws or regulations, speak up immediately to your leader, Human Resources or the Ethics & Compliance (E&C) Helpline. Leaders have a duty to act when coworkers raise issues about safety or misconduct. Leaders also have a responsibility to listen, take action and follow up on issues raised by coworkers.

PG&E takes fraud, bribery, corruption and other misconduct seriously. Coworkers who violate this Code of Conduct and suppliers who violate the Supplier Code of Conduct will be held accountable for their actions. Coworkers who engage in this type of misconduct are subject to discipline or termination of employment, and may also face criminal prosecution.

You can feel comfortable raising a concern, sharing ideas or requesting guidance without fear of retaliation; however, sometimes speaking up is easier said than done. Please consider the consequences if you stay silent—to yourself, your coworkers and to PG&E. The goal of a speak-up culture is to have an environment where we all feel welcome to express concerns, share new ideas or request guidance.

What is misconduct?

Misconduct is behavior that violates this Code of Conduct, PG&E policies, standards or procedures, or laws or regulations. Misconduct may be a willful or intentional act, an unintentional act, or a failure to act. Misconduct is serious and may result in discipline or termination of employment.

Examples of misconduct include but are not limited to:

Retaliation

Improper use of drugs or alcohol

Acts or threats of violence

Fraud, bribery or corruption

Unethical conduct

Falsification of company records, including inspection forms, time sheets and expense reports

Conflicts of interest

Theft and inappropriate sharing of company data

Harassment and discrimination

Failure to comply with accounting procedures or practices, such as submitting or approving false or misleading information    

Violations of the law

Any conduct inconsistent with our Virtues

Read our Employee Conduct Standard. (CDT-1004S)

REQUESTING GUIDANCE AND REPORTING CONCERNS

It’s your responsibility to raise concerns about safety or misconduct, including violations of laws, regulations or internal requirements. If you are uncertain about a situation, you have a duty to seek clarification and guidance on interpretations of the Code, safety issues, ethics, compliance and legal issues. We all have a responsibility to identify and internally report potential safety and operational issues (you can read about this in more detail in the Building Trust with Governments section of this Code in Section 08).

HOW YOU CAN SPEAK UP

You have many ways to speak up to voice a concern. You can contact your immediate leader. If the issue involves your leader or you are uncomfortable with that approach, consider elevating your concern to the next level of management. Know that you are not required to go to a leader. Here are some additional options.

Emergency concerns

If there is a life-threatening or emergency situation, contact 911 and seek emergency care immediately.

If there is workplace violence concern, contact Corporate Security at 1-800-691-0410. If the concern is urgent, contact 911.

Coworker conduct and guidance

Contact the E&C Helpline 24/7 at 1-888-231-2310 orwww.pgecorp.ethicspoint.com to report violations of our Code of Conduct, accounting issues or illegal activity. You may remain anonymous if you wish. To request guidance or ask questions about the Code of Conduct, policies, standards or procedures, contact the Ethics & Compliance Department at EthicsComplianceHelp@pge.com. If you are not sure where to turn, the E&C Helpline will determine where to take the issue and provide you with guidance on next steps.

Unsafe work practices and process concerns

Contact the Corrective Action Program (CAP) at 1-855-85-GO-CAP to report safety and equipment issues, non-compliance, ineffective or inefficient work processes and procedures, and process improvement ideas. You may remain anonymous if you wish.

Safety incidents and injuries

If you experience a work-related illness or injury, including any injury that affects your ability to work pain-free, you should call the 24/7 Nurse Care Line at 1-888-449-7787 right away and notify your supervisor.

In life-threatening or emergency situations, call 911 and seek emergency care immediately.

In addition, Diablo Canyon Power Plant and Humboldt Bay Power Plant coworkers and contractors may contact the Employee Concerns Program (ECP) Hotlineat 805-545-4994

or ECPHotline@pge.com to request guidance or report nuclear safety and nuclear quality concerns.

GOOD FAITH REPORTING AND OUR POLICY AGAINST RETALIATION

At PG&E, we don’t tolerate retaliation against anyone who raises good faith concerns or has cooperated in an investigation. Coworkers may not retaliate or threaten retaliation. Leaders may not tolerate retaliation that they observe against another coworker, and have a duty to act to prevent and report retaliatory actions that come to their attention. Retaliation is harmful and can have a chilling effect on other coworkers in raising concerns.

What is retaliation?

Retaliation is adversely changing a coworker’s condition of employment for a non-business reason. It occurs when a coworker or leader takes or threatens to take an adverse, non-business-related action against a coworker who has raised a concern or cooperated in an investigation. Examples include threatening a coworker for raising a concern or moving their physical location without a legitimate business reason. A coworker who speaks up in good faith will not be put at any disadvantage by PG&E as a result of their report.

INVESTIGATING REPORTS OF MISCONDUCT AND UNSAFE WORK PRACTICES

PG&E takes reports of misconduct and unsafe work practices seriously. Your role is to bring forward allegations and unsafe work practices to leaders. You must cooperate with investigations by promptly responding to information requests. Be sure to provide complete, truthful and accurate information. Leaders must take action on issues brought to their attention, including reaching out to other resources such as:

E&C Helpline for misconduct issues and guidance on policies

CAP for unsafe work practices, non-compliance and process improvements

OUR MISCONDUCT INVESTIGATIONS PROCESS:

1.    Report: A coworker, supplier or customer raises a potential misconduct allegation to their leader, Human Resources or the E&C Helpline.

2.    Assign: Ethics & Compliance reviews the report and determines the appropriate next step, which in many cases will include an investigation. The investigation may be conducted by PG&E resources, including Human Resources or Corporate Security, or by outside investigators. If no investigation is needed, move to step 5.

3.    Investigate: The internal or external investigator begins an investigation, if warranted. This may include interviews and/or a review of relevant documents, data or materials.

4.    Record: The investigator documents the case findings. When the investigation is complete, the appropriate PG&E leaders are notified and the outcome is recorded in PG&E’s case management system.

5.    Resolve: Based on the findings, Human Resources and the business group work together to determine the appropriate next steps, which may include training, policy modification, disciplinary action or termination of employment. Regardless of the outcome of the investigation, the coworker, supplier or customer who raised the concern will be notified that the investigation has been concluded.

6.    Track and analyze: Ethics & Compliance tracks, analyzes and provides guidance to lines of business and PG&E leadership on trends and issues.

For more information, read our Employee Conduct Standard. (CDT-1004S)

OUR UNSAFE WORK PRACTICE INVESTIGATIONS PROCESS:

To learn more about the CAP process, read these standards:

Safety Incident Notification and Response Management Standard (SAFE-1004S)

Enterprise Cause Evaluation Standard (GOV-6102S)

(Section 05)

PG&E maintains a safe and secure working environment. We do not tolerate behavior that is offensive or hostile.

Section 05

Building Trust with Each Other

Diversity, Equity and Inclusion are key to PG&E’s Purpose, Virtues and Stands.

Equal Employment Opportunity

Diversity, Equity and Inclusion are key to PG&E’s Purpose, Virtues and Stands, and we strive for a workplace that respects individual differences, perspectives and talents. We prohibit discrimination, harassment, abusive conduct, bullying and retaliation, and we work to ensure our policies, standards and procedures reinforce this. It is Who We Are.  

Fair wages—We are committed to paying fair wages, salaries and benefits.

•    Freely-chosen employment—We do not participate in the exploitation of workers or use forced or involuntary labor, including human trafficking.

•    Child labor—We do not employ any person under the minimum legal age for employment as prescribed by the relevant local authority, or under the age

for completing compulsory education, whichever is greater.

•    Anti-discrimination—We give all coworkers equal opportunities for jobs, skills training and promotions.

•    Human rights—We conduct our business in a manner that respects the human rights of all. We treat our coworkers with dignity and provide them with safe and humane working conditions.

Read the PG&E Human Rights Policy. (GOV-12)

AS A PG&E COWORKER—

•    I will create a work environment that embraces Diversity, Equity and Inclusion.

•    I won’t discriminate, harass or retaliate against any applicant, coworker, customer or supplier.

What are examples of individual characteristics or actions protected from discrimination and harassment?

Race, color

Ancestry, national origin

Sex (including pregnancy, childbirth, breastfeeding, or related medical conditions)

Sexual orientation

Gender, gender identity, gender expression, sex stereotyping

Transgender status

Age

Religion, religious creed

Physical or mental disability

Medical condition

Marital status

Genetic information

Military and veteran status

Citizenship

Protected medical leaves

Domestic violence victim status

Political affiliation

Any other status protected by federal, state or local laws or any other non-job-related factor

See our Equal Employment Opportunity and Affirmative Action Policy.

Read our Mothers’ Room Standard. (SAFE-2105S)

HARASSMENT-FREE WORKPLACE

PG&E does not tolerate harassment of any kind, including sexual harassment. This policy includes any conduct, communication, text message, image, data, sound, social media post or other information that is inappropriate, offensive or contains material of a sex-based nature. Coworkers who witness or experience harassing behavior have a duty to speak up and report it. Coworkers who engage in harassment will face disciplinary action, including potential termination of employment.

Read our Policy for a Harassment, Discrimination and Retaliation-Free Workplace.

What is harassment?

Some examples include:

Bullying

Hazing

Offensive or hostile behavior or other verbal, written or electronic communication that singles out a coworker on the basis of a protected characteristic

Behavior that unreasonably targets another coworker

Conduct that creates an intimidating work environment

Conduct that interferes with a coworker’s ability to do the job

Sexual harassment (unwelcome sexual advances, requests for sexual favors, or other verbal, written or electronic overtures or physical contact of a sexual nature)

PG&E does not tolerate harassment of any kind. If you see something, speak up.

CONDUCT OUTSIDE OF WORK

Your conduct away from company property and outside of business hours could have a negative effect on your coworkers, the public, workplace safety, on PG&E’s reputation and on our ability to serve customers.Conduct outside of work includes social media posts brought to PG&E’s attention that violate our Code of Conduct.

PG&E will assess off-duty conduct that is potentially harmful to PG&E, our coworkers, or customers on a case-by-case basis and determine appropriate action(s).

HEALTH AND SAFETY

VIOLENCE-FREE WORKPLACE

PG&E maintains a safe and secure workplace and working environment. Coworkers who engage in acts or threats of physical violence, intimidation, harassment, stalking, sabotage or vandalism may be disciplined or terminated from employment.

Weapons

We do not permit weapons in our workplace or on our job sites. Weapons may not be brought, carried, stored or used on property or in vehicles that are PG&E-owned, leased or rented, or in a personal vehicle while being used for PG&E business, unless there is an authorized and legitimate business reason to do so.

What is permitted on PG&E property or job sites?

Tools used for legitimate PG&E business purposes

A personal defense product (including pepper spray or electric shock products that do not fire a projectile; firearms are NOT permitted)

Small pocketknives with a blade length of three inches or less

AS A PG&E COWORKER—

I won’t bring a weapon onto company property or a job site, a company vehicle or a personal vehicle used for company business unless authorized by Corporate Security.

SECURING OUR PEOPLE, PROPERTY AND ASSETS

PG&E is committed to creating a safe environment and taking care of our assets. All coworkers must perform their work in a manner that safeguards the public, our customers, coworkers and PG&E. Doing so is critical for providing safe, reliable, affordable and clean energy.

Securing our people

As a member of PG&E’s workforce, you are crucial in the fight against acts of sabotage, crime and terrorism. Your daily duties place you in a position to observe and report such instances as

unknown people or packages and open doors or gates on our premises. If you see something, speak up. This is how we improve our safety.

Protecting our technology

As an energy provider, we share the responsibility for keeping California’s energy networks running. Securing our technology is integral to carrying out this responsibility. Helping to secure that technology is the personal responsibility of every PG&E coworker.

Coworkers must follow these technology practices:

Only authorized computers and equipment may be connected to PG&E networks

Only approved, authorized and properly licensed software and applications may be used on PG&E IT assets, including computers, tablets and smartphones

Never click on links or open email attachments unless the email is expected and you know and trust the sender

Only use technology assets outside the U.S. if you’ve received pre-approval and follow security guidelines for international travel

Never transfer company data or personal information outside PG&E without following company guidelines. This includes:

o    Transferring PG&E information to a personal computer, phone, cloud storage, external hard drive or any other device or location

o    Emailing PG&E information to a personal email account

o    Exception: Your personnel information, such as W2s, pay stubs and benefits, may be sent to your personal email account

Limited personal use of certain PG&E assets is permitted if the use is minor and incidental to business. This includes personal computers, phones, scanners, copy machines and conference rooms. For example, you can occasionally make a personal phone call using your PG&E-owned device. However, personal use of company vehicles is not permitted. PG&E assets are monitored, and coworkers should have no expectation of privacy when using them.

Coworkers who are issued PG&E-owned devices, such as smartphones, should conduct company business on their PG&E-owned devices—not on their personal devices.

Communications, including emails and text messages, should always be respectful of our coworkers, customers, and other stakeholders. PG&E will take action in response to communications that are in conflict with our Virtues.

Read ourSoftware ManagementStandard(IT-1001S) and User Responsibilities Standard. (SEC-1001S)

Property and other PG&E assets

Proper treatment of PG&E assets, including digital assets, protects PG&E’s critical infrastructure, the safety of the electric grid, generation assets and gas pipeline system, and our customers’ and coworkers’ data. Coworkers are responsible for the proper acquisition, use, maintenance, protection and disposal of PG&E assets. Misuse or theft of PG&E assets,

including taking or using company materials for personal use, will result in disciplinary action or termination of employment.

Misuse or theft of PG&E assets, including taking or using company materials for personal use, will result in disciplinary action or termination of employment.

What are PG&E assets?

Does PG&E own it, rent it, or lease it? If the answer is yes, it’s a PG&E asset.

Tangible assets include materials, computers, phones, tablets, tools, real property, vehicles, physical structures, meters and equipment.

Intangible assets include data, information and records concerning PG&E coworkers, suppliers or customers, and intellectual property and non-public information about PG&E.

AS A PG&E COWORKER—

•    I will be diligent in protecting PG&E’s technology system.

•    I will physically secure mobile devices.

•    I will observe all information security controls and never try to circumvent them.

•    I will immediately report any suspected or actual breach of PG&E’s computer

•    systems and networks to the Technology Solution Center (TSC) at 415-973-9000.

•    I will speak up about security concerns, including unknown people or packages and open doors or gates.

•    I won’t let others tailgate into PG&E facilities and will follow proper badge protocol.

•    I won’t take, misuse or divert any PG&E assets for any reason.

•    I will respect limits on personal use of PG&E assets.

AS A PG&E COWORKER—

I will be diligent in protecting PG&E’s technology system.

FITNESS FOR DUTY

Coworkers are expected to be mentally and physically fit for duty, and to remain fit while on duty. If your fitness for duty is called into question, you may be subject to a mandatory fitness for duty assessment and/or U.S. Department of Transportation (DOT) or non-DOT Reasonable Suspicion testing.

Violation of fitness for duty policies or alcohol-free and drug-free workplace standards will result in disciplinary action or termination of employment.

Alcohol-free and drug-free workplace

Working under the influence of alcohol or drugs, including recreational and medical marijuana, is prohibited. This includes working remotely, on company property or at a jobsite. Coworkers may not transport alcohol or drugs in a company-owned, rented or leased vehicle, or a personal vehicle while on company business.

Authorized use of alcohol

In rare circumstances, coworkers may seek and obtain prior consent from a director or officer to transport alcohol in a company-owned, rented or leased vehicle. Alcohol is not permitted at company events unless an officer provides prior written approval for consuming alcohol for special occasions or certain business meetings. This must be limited and must not violate regulations. Do not operate a company vehicle after consuming alcohol.

If you attend a conference on behalf of PG&E and alcohol is served in the evening at a reception or meal, you may consume alcohol in moderation. However, be mindful that your actions impact PG&E’s reputation, and you may not conduct official business while under the influence of alcohol. Also, you may not drive a company-owned, rented or leased vehicle or a rental vehicle after consuming alcohol at an event.

Read PG&E’s Employee Business Expenses and Travel Standard. (FIN-2210S)

AS A PG&E COWORKER—

•    I won’t report to work under the influence of alcohol, illegal drugs or marijuana.

•    I won’t consume, possess, display, transport or sell alcohol, recreational or medical marijuana or illegal drugs while on duty, on PG&E property or a jobsite, in a PG&E vehicle, or in a personal vehicle while on company business.

•    I will tell my leader if I am taking any medication that could affect my ability to work safely and efficiently.

•    I won’t report to work under the influence of prescription or over-the-counter medications that could impair my ability to work safely and efficiently.

•    I will comply with PG&E’s alcohol and drug standards and all fitness-for-duty policies and regulations.

ACCURATE DATA, RECORDS AND REPORTING

Accurate data 

Capturing and managing data effectively is critical for PG&E’s operations. 

Data management is a business-driven, enterprise-wide, shared responsibility that covers the full lifecycle of data. It includes the creation, storage, access, controls, governance, quality, meta-data, usage, analysis, security, retention and disposal of data. 

Read the Enterprise Data Management Policy. (GOV-09) 

What is data?

Data refers to the raw facts or figures that form the building blocks of information. 

How is data different than information or a record?

Data are raw, unorganized facts that need to be processed. Information is a collection of data that has been given value through analysis, interpretations or compilations in a meaningful form.

Information may be deemed a record or a non-record. Information, regardless of format, that documents business actions, transactions, decisions, and/or contractual, legal or regulatory obligations are defined as records. 

ACCURATE RECORDS 

Accurate records are an essential part of PG&E’s operations. To keep our system safe and reliable, we must always complete and document our work. 

Each coworker creates records and information. We are all responsible for managing PG&E records and information to verify they are complete, accurate, reliable, secure and available throughout their lifecycle. 

Records must be managed and stored in accordance with specific PG&E policies, standards and procedures, including the Enterprise Records Retention Schedule. The schedule lets coworkers know how long records need to be retained.   

Some company records may contain personal information or personal health information. See the Personal Information section for more details. These should only be accessed by coworkers with a business need to know and should be stored according to PG&E requirements for storage of confidential or restricted information.

Read the Enterprise Records and Information Management Standard. (GOV-7101S)

For guidance on recording meetings, read thePG&E Recording of Meetings Standard. (GOV-7116S)

What is a record?

Any information, regardless of format, that is created, received and/or maintained that documents business actions, transactions or decisions, including supporting documents. Records also include contractual, legal or regulatory requirements or obligations, and PG&E policies, standards and procedures. 

Examples of company records

Maintenance records and inspection documents

As-built drawings

Personnel documents

Reports to government agencies or other public communications

Workers’ compensation or other benefit-related information, such as dependent eligibility

Financial reports

Payroll records, including timecards

AS A PG&E COWORKER—

I will follow proper record management practices.

What is fraud?

Fraud is an intentional, deceitful act, committed to obtain some illegal or unfair gain or advantage. There are numerous types of fraud. For example, fraud can occur when a person misrepresents or conceals facts, or makes intentionally misleading allegations. Some additional examples of fraud may include falsifying documents, misusing company

credit cards, splitting invoices or expense reports to avoid approval thresholds, intentionally overcharging customers or changing a family member’s account in our billing system.

Coworkers who engage in this type of misconduct—or who assist suppliers in this type of misconduct—are subject to discipline or termination of employment, and may also face criminal prosecution.

Fraud also includes falsifying time reporting for purposes of a personal advantage. Coworkers are responsible for the accuracy of their own work-time submissions, even if timecards are completed by others. Review your claimed work times to confirm accuracy before you submit them into the timekeeping system.

For guidance on timecards, read our Time Reporting Standard. (HR-1250S)

Fraud prevention and internal accounting controls

PG&E is committed to maintaining accurate books, records and accurate financial and non-financial reporting. PG&E actively monitors for many types of fraud and continues to put controls in place to detect fraudulent activity. Fraud will not be tolerated and leaders may not direct their coworkers to commit fraud on their behalf.

Business expenses

Misrepresentation of business expenses is also fraud. Use PG&E funds for PG&E business expenses only, whether paying by credit card, cash or another method. No personal use is allowed on PG&E credit cards.

Business expenses must be:

Reasonable

Prudent

Actual

Necessary

Incurred while on PG&E business

AS A PG&E COWORKER—

I will follow proper record management practices.

I won’t use company funds to make unauthorized or personal purchases.

I won’t incur unreasonable expenses on behalf of PG&E.

Read our Employee Business Expenses and Travel Standard. (FIN-2210S)

CONFLICTS OF INTEREST

You must not use PG&E property, corporate assets, corporate opportunities, company information or the influence of your position in a manner that places your personal interests and/or the interests of a competitor before the interests of PG&E.

AS A PG&E COWORKER—

I will disclose any potential conflict of interest to my leader.

If I find myself facing a situation that might be perceived as a conflict of interest, I won’t proceed without a written agreement from my leader or appropriate decision maker.

What is a conflict of interest?

A conflict of interest occurs when a coworker’s private interests interfere, or even appear to interfere, with the interests of PG&E.

Influencing business decisions for personal gain

A potential or actual conflict of interest exists if you influence or try to influence a decision or transaction that could materially affect the value of a financial interest that you hold or that is held by a member of your family or another person with whom you have a close relationship.

Review our Conflicts of Interest Standard. (CDT-1005S)

Favored treatment

We don’t tolerate favored treatment, which is using your position to obtain preferential or advantageous treatment for yourself or your close personal relationships. This includes hiring or promoting coworkers, selecting contractors or suppliers, or participating in investment or other opportunities to which you’re made privy as a coworker of PG&E.

Refer to the Nepotism Policy. (HR-01)

AS A PG&E COWORKER—

I will treat all fellow coworkers fairly.

If I’m in a leadership position, I’ll make personnel decisions based on merit and performance.

I will disclose close personal relationships to my leader to combat the appearance of favoritism or a conflict of interest.

As a PG&E coworker—

I will treat all fellow coworkers fairly.

Gifts

We protect our ability to make business decisions free of undue influence. If you give or receive a gift in a business setting, it can create a sense or appearance of obligation that taints neutral decision-making. That’s why PG&E has very specific standards about what you may receive from suppliers, business contacts and customers.

We may not offer or accept gifts of any value, other than items of no intrinsic value. Items of no intrinsic value include promotional items, such as a pen or baseball cap with a logo, valued at $15 or less. PG&E coworkers, immediate family members, contractors, consultants, those seeking to do business with PG&E and our suppliers, are all subject to the same rules regarding gifts.

Check our standard. Before you accept or reject, go or don’t go – know what’s permitted in the Conflicts of Interest Standard (CDT-1005S).

If you’re not sure, ask. If the right course of action is not clear after consulting the standard, seek guidance from your supervisor or the E&C Helpline at EthicsComplianceHelp@pge.com.

Return gifts that violate this policy to the giver with an explanation of our no-gift policy, and notify the E&C Helpline at EthicsComplianceHelp@pge.com. If you return a gift to the giver within 30 days, or reimburse the giver from personal funds, it is not considered a gift.

The rules surrounding providing items of value to federal, state and local government officers, officials and coworkers may be more restrictive than PG&E’s gift policy.

Refer to our Conflicts of Interest Standard (CDT-1005S) for more guidance.

What is a gift?

A gift can be anything of value, including:

A ticket to a sporting event, concert, play or other entertainment event

A round of golf

A non-business meal

A bottle of wine

A free service (car detail, free parking, etc.)

A special discount not available to all coworkers

An all-expenses-paid trip to a conference or trade show

A ticket to a charitable or fundraising event given to a PG&E coworker by a third-party

Perishable food items, such as a fruit basket or box of chocolates

Cash

Tips or gratuities

Gift cards

What is a supplier?

An individual or organization that does or is actively seeking to do business with PG&E.

A supplier sent me a supplier-branded baseball cap. What should I do with it?

Keep it. It is OK to accept an item of no intrinsic value, such as a promotional pen or baseball cap with a logo valued at $15 or less.

A supplier sent me a bottle of wine as a holiday gift. What should I do with it?

Return the bottle of wine to the supplier with an explanation of our no gift standard.

AS A PG&E COWORKER—

I won’t accept or give gifts.

I will ask my leader or Ethics & Compliance if I have questions about gifts.

I will check with my leader if I plan to pursue outside employment opportunities.

Customary business meals and conference attendance

Customary business meals are not considered gifts. These are routine meals that are similar in cost to PG&E coworkers’ meals when they travel for business.

If a coworker is a guest speaker at a conference hosted by a supplier or other third party, the conference host may pay the coworker’s conference registration fee, in addition to customary business meals. PG&E is responsible for paying the coworker’s airfare, lodging, entertainment and other expenses associated with attending the conference.

Outside employment

You’re not permitted to engage in outside employment or activities such as joining the board of directors of companies that compete with products or services offered by PG&E. Additionally, coworkers are not permitted to take outside employment that has or could have a negative effect on their ability to do their job at PG&E, or which otherwise could create a conflict of interest. If you are, or plan to be, engaged in outside employment or activities, notify your leader and contact Ethics & Compliance for more guidance.

Loans, wage advances or guarantees of obligations

PG&E prohibits loans, wage advances or guarantees of corporate funds to its coworkers or their friends and family members.

Coworkers or members of their families must never accept a loan, guarantee, service or payment from a contractor, supplier, consultant or others doing business with PG&E under terms that are not available to the public.

Insider trading

Insider trading is illegal. Never disclose or “tip” inside information to others, or buy and sell securities based on material information you receive as a coworker of PG&E.

Refer to PG&E’s Insider Trading Policy for more information. (CDT-1002S)

What is material information?

Information is “material” if a reasonable investor would consider it important in making an investment decision. Examples include financial results, earnings projections, significant developments in major rate cases or other proceedings, matters before the California Public Utilities Commission, significant cybersecurity issues, major litigation, changes in dividend policy or senior management, major events regarding PG&E’s securities, mergers and acquisitions, or disposition of significant assets.

What is insider trading?

Insider trading is buying and/or selling stock or other securities—including PG&E Corporation Retirement Savings Plan (the 401(k) plan) transactions—while in possession of material non-public information.

(Section 06)

As our suppliers are an extension of PG&E, we expect them to deliver on our safety stand that everyone and everything is always safe.

Section 06

Building Trust with Our Business Contacts

We do business honestly, fairly and lawfully.

DOING BUSINESS FAIRLY

We do business honestly, fairly and lawfully. We respect our competitors and do not make inaccurate or derogatory statements about their products or services.

INTELLECTUAL PROPERTY AND CONFIDENTIAL INFORMATION

Intellectual property and other confidential information should remain within PG&E and not be shared with outsiders. Examples of protected information are competitive strategy, costs and financing methods, trade secrets, pricing policy, contract terms, market surveys, and capacity plans and capabilities. If you are authorized by a director or officer to share confidential information outside PG&E, you must obtain a signed non-disclosure agreement from the third party to whom you disclose the information.

Works created by a coworker within the scope of their employment are considered the sole intellectual property of PG&E—not the property of any coworker. Tell your leader about inventions and developments that you create within the scope of your employment and with the use of PG&E resources.

AS A PG&E COWORKER—

I won’t view confidential information for a non-business reason.

I won’t use confidential information for personal gain.

I won’t share confidential information without the appropriate approval.

Copyright laws make it illegal to copy or reproduce materials without permission of the owner. Examples of copyright-protected materials are books, newspapers, movies, computer software, drawings and musical recordings.

Patents are exclusive rights granted by a government to an inventor to manufacture, use or sell an invention for a certain number of years.

Trademarks are words, symbols, slogans and phrases that distinguish goods and services from others and are used to build brand identity.

Trade secrets include any information used by a business, such as formulas, devices or customer lists that have economic value but are not generally known and for which reasonable efforts have been made to preserve secrecy.

AS A PG&E COWORKER—

I will keep PG&E’s intellectual property and trade secrets confidential and will not disclose them to any outside party without prior approval from my director or officer.

I won’t make unauthorized copies of software licensed to or created by PG&E.

I won’t load unlicensed software onto PG&E computer equipment or download unauthorized software from the internet.

I will tell my leader about inventions and developments that I create within the scope of my employment and with the use of PG&E resources.

BRIBERY AND CORRUPTION

PG&E does not tolerate any form of bribery, corruption, extortion or embezzlement and we expect our suppliers, coworkers and contractors to adhere to this same standard. We neither offer nor accept bribes, kickbacks, facilitation payments or any other similar inducements.

Bribery and corruption have a negative effect on PG&E’s reputation. Coworkers who engage in this type of misconduct are subject to discipline, including termination of employment, and may also face criminal prosecution.   

  

The Foreign Corrupt Practices Act (FCPA) prohibits giving or offering anything of value to a foreign official, inside or outside the United States, to influence or induce the recipient to misuse their official position to obtain or retain business or secure an improper advantage. When you are traveling and working with foreign officials, be careful not to violate the FCPA. Contact the E&C Helpline at EthicsComplianceHelp@pge.com with any questions, particularly concerning gifts and meals.

Read the Foreign Corrupt Practices Act Standard. (CDT-1006S)

Antitrust and other laws, sanctions and controls

PG&E complies fully with all the following:

Antitrust laws were established to promote economic competition among businesses. Activities that limit competition, restrict trade or otherwise dominate a market may violate antitrust laws. Such violations can expose PG&E and individual coworkers to criminal penalties, fines and civil lawsuits.

Anti-boycott laws make it illegal to participate in any boycott between foreign countries if not otherwise sanctioned by U.S. law.

Treasury embargo sanctions prohibit U.S. companies and their foreign subsidiaries from doing business with certain countries, agencies and individuals.

Export and import controls restrict or prohibit the export and import of sensitive goods, technology or software to certain countries or individuals.

AS A PG&E COWORKER—

I won’t accept or make any offers from/to a supplier that could be viewed as a bribe or unethical payment in expectation of favored treatment.

I will promptly report any such instance of attempted bribery, corruption or extortion to my leader or the E&C Helpline.

What is a kickback?

A kickback is a “thank you” for favorable treatment under a contract. Examples of kickbacks can include:

A customer gives a coworker a gift card to expedite their service connection

A supplier thanks a coworker for a bid selection by offering them a trip

What is a facilitation payment?

A payment made to a government official to facilitate approval of a business transaction or activity.

What is a bribe?

Money or a favor given or promised to influence the judgement or conduct of another person.

WHO WE WORK WITH AND WHY

Suppliers are vital to PG&E’s success. Because suppliers are a visible extension of PG&E in our communities, we choose them carefully based on fair and objective criteria. We expect

all our contractors and suppliers to behave ethically and comply with applicable laws, regulations and policies, and our Supplier Code of Conduct.

SUPPLIER CODE OF CONDUCT

As our suppliers are an extension of PG&E, we expect them to adhere to our Purpose, Virtues and our Stands and put safety first. The PG&E Supplier Code of Conduct is the standard of conduct that all suppliers, as well as their employees, subcontractors and sub-suppliers, must follow as they provide goods and services to PG&E. Failure to comply with the expectations covered in the Supplier Code of Conduct could result in termination of an assignment and/or contract, and may also result in criminal prosecution.

If you are aware of any supplier misconduct or unsafe practices, please speak up by contacting the E&C Helpline at 1-888-231-2310.

Read our Supplier Code of Conduct.

AS A PG&E COWORKER—

I will report suspected supplier misconduct.

If I am in a leader or managerial role, I will ensure that any suppliers I work with understand and comply with the Supplier Code of Conduct.

What does the Supplier Code of Conduct cover?

Topics include:

Health and safety

Environmental leadership

Supplier diversity

Labor issues and human rights

Ethical business conduct

Conflicts of interest

Engagement with external third parties

General administrative topics

As a PG&E coworker—

I will report suspected supplier misconduct.

(Section 07)

PG&E serves our communities by protecting and preserving our environment, protecting sensitive information and communicating honestly and openly about our business.

Section 07

Building Trust with Our Communities and Customers

At the center of our Purpose, Virtues and Stands is our commitment to a sustainable energy future.

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PG&E’s responsibilities as an energy provider go far beyond our core mission of providing safe, reliable, affordable and clean energy to our 16 million customers. We also have a responsibility to build a better future for everyone whose lives we touch.  

At the center of our Purpose, Virtues and our Stands is our commitment to a sustainable energy future. Our stand is a healthy environment and carbon-neutral energy system shall be the reality for all Californians.  

Serving our planet also affirms our commitment to meeting the challenge of climate change—a key driver for California’s energy policy and a critical priority for our customers.  

PG&E serves our communities by protecting and preserving our environment, protecting sensitive information and communicating honestly and openly about our business. We strive to represent ourselves consistently and with integrity. We work in partnership with our communities to improve the quality of life everywhere we serve.

As a PG&E coworker—

I will carry out my duties in an environmentally responsible manner.

PRESERVING OUR ENVIRONMENT

PG&E is committed to environmental leadership and to conducting business in an environmentally sensitive manner. The cornerstone of our environmental policy is strict compliance with all applicable environmental laws and regulations.

We also seek opportunities to exceed current standards of environmental protection, including in the areas of pollution prevention, climate protection, and habitat and species protection. Our annual Corporate Sustainability Report is one way we measure and communicate our progress; we hold ourselves accountable and report on our performance with transparency.

Read our Environmental Policy. (ENV-01)

AS A PG&E COWORKER—

I will understand the impact of my job on the environment.

I will carry out my duties in an environmentally responsible manner.

PERSONAL INFORMATION

As part of your job duties, you may have access to personal information in digital, hard copy or verbal form. This includes the personal information of PG&E customers, coworkers or suppliers. You must maintain the confidentiality and privacy of this information, and you may only access or disclose it with proper authorization or when legally mandated.

What is personal information?

Personal information is any data that could potentially identify a specific individual.

What is protected health information?

Protected health information includes personal data about medical conditions, medical treatment, medical history, occupational injuries or health care coverage.

What is customer and/or coworker personal information?

Personal information is any information that, when used alone or combined with other information, can distinguish or reveal the identity of a PG&E coworker, customer, stakeholder, or any other California resident.

Examples of customer personal information include:

Customer name

Address

Phone number

Social Security number

Customer energy-usage data

Online username, password and IP address

In addition to the items above, examples of coworker personal information include:

Salary and benefits information

Health information

Photographs

Performance evaluations

For a more comprehensive list, review the Information Classification and Protection Standard. (IT-5302S)

What is supplier information?

Supplier information includes pricing and contract information.

AS A PG&E COWORKER—

I will respect every customer’s right to privacy and handle customer information with care and diligence.

AS A PG&E COWORKER—

If I am unsure how to collect, access or protect personal information, I will reach out to the Privacy team at pgeprivacy@pge.com.

Customer personal information

Do not disclose customer personal information to a third party without the customer’s written authorization unless you are legally required to do so, or the information must be disclosed in order for PG&E to provide services. You also must ensure appropriate contractual privacy and security protocols are in place.

Coworker personal information

Coworkers, including leaders, should not share or discuss the protected health information of others with those who do not have a business need to know. Never disclose coworker personal information or protected health information to another coworker, shareholder or a third party without appropriate approval. Forward requests for coworker personal information, protected health information and references to your Human Resources business partner.

Supplier information

Never disclose supplier personal information or other information subject to confidentiality provisions to a third party without appropriate approval and a legitimate business reason. You also must comply with any non-disclosure agreement or confidentiality provisions of a supplier agreement.

If you have access to personal information, you must follow all PG&E standards to ensure that it is appropriately protected and secured. This obligation continues even after you are no longer employed by PG&E.

If you have any questions about using, handling or disclosing personal and sensitive information, please contact pgeprivacy@pge.com.

Read our privacy policies and standards:

–    PG&E Privacy PolicyPrivacy Policy (GOV-08)

–    Privacy Policy (GOV-08)

–    Employee, Job Applicant and Contractor Privacy Notice

–    Information Classification and Protection Standard (IT-5302S)

–    Privacy Standard (GOV-8001S)

AS A PG&E COWORKER—

I will respect every individual’s right to privacy and handle personal information with care and diligence.

I will never view, change, update, manipulate or disseminate my own account or the account of a family member, friend or coworker from our internal system.

I will show respect to fellow coworkers by treating their information with the same care and diligence I would expect in the handling of my own information.

I won’t access or view personal information for a non-business reason or for personal gain.

I won’t share personal information without appropriate approval.

AS A PG&E COWORKER—

I won’t share personal information without appropriate approval.

COMMUNICATING WITH CUSTOMERS AND THE PUBLIC

Our communication with customers and the public should be clear, accurate, open and consistent, and should always demonstrate utmost concern for the public’s benefit and safety.

How to respond to inquiries from the media, including during emergencies

If you are contacted by the news media, immediately refer the contact to PG&E Marketing

and Communications at 415-973-5930. Do not attempt to improvise an answer, speculate, or downplay the seriousness of the situation. A Marketing and Communications representative is available 24 hours a day, seven days a week to respond to the news media. Marketing and Communications also handles requests for PG&E subject matter experts.

Social media

PG&E respects your right to participate in social media and understands that your time outside of work is your own. Social media used appropriately and effectively can help PG&E build and strengthen relationships with our customers, coworkers and community members.

Social media activity brought to PG&E’s attention that violates PG&E’s Code of Conduct will be reviewed for potential disciplinary action or termination of employment. PG&E will assess such social media activity on a case-by-case basis and determine appropriate action(s). The assessment will include whether the activity includes threats or allusions to violence and/or offensive content (e.g., hate speech) and whether it could reasonably lead to reluctance on the part of other coworkers or customers to work with the coworker.

PG&E applies the requirements in this Code of Conduct in a manner that does not interfere with or limit coworkers’ rights under the National Labor Relations Act. Legally protected social media discussions include discussions about wages, hours and working conditions; the right to self-organize, form, join or assist labor organizations; the right to bargain collectively through representatives of your choosing regarding your wages, hours and working conditions; the right to engage in other concerted activities about the same topics or other mutual aid or protection; or to refrain from engaging in such activities.

Read the Employee Social Media Standard. (CDT-1003S)

How does PG&E define social media?

Social media includes:

All types of posts and other communications on the internet

Posts on social networking sites, such as Facebook, Twitter, Instagram and LinkedIn

Video or audio posted to media-sharing sites, such as YouTube or TikTok

AS A PG&E COWORKER—

I will act with integrity and respect in all my communications with my coworkers, our customers and all stakeholders.

I will use social media responsibly to balance the benefits and risks to PG&E and to me personally.

I will use my personal email account (not my PG&E email) and my personal device(s) when setting up or participating in external social media channels.

I will adhere to copyright and fair use laws.

I won’t represent in any social media content that I am authorized to speak on behalf of PG&E without prior written approval from Marketing and Communications.

CORPORATE PRESENTATIONS, IDENTITY AND LOGO USE

PG&E is committed to fair and truthful advertising practices. PG&E Corporation owns the trademarks that incorporate “PG&E” and the holding company and utility corporate names. You may use the corporate names and logos, the PG&E logo and PG&E colors in presentations to public audiences in compliance with the standards issued by Marketing and Communications. When creating presentations or other materials, do not use copyright-protected images; some stock and company imagery is available for your use on the brand guidelines website.

Review our brand guidelines at www.pgebrandguidelines.com (Login: pgebrand, Password: onepge); contact brandguidelines@pge.com with questions.

Endorsements

PG&E does not endorse products or services, or the firms or individuals who supply them. Favoritism must not be implied by testimonials or endorsements. If you want to provide a personal testimonial or endorse an event, product or service, do not use your job title

or affiliation. If you have questions about endorsements, please contact the E&C Helpline. Any exceptions must be approved by Marketing and Communications.

Publishing material to external sources

If you plan to publish material about your job responsibilities or work, get approval from your leader and Marketing and Communications before publication.

Donations

Community Relations must review in advance all cash and in-kind contributions made in PG&E’s name to 501(c) nonprofit organizations, public schools and governmental entities. We serve our community through coworker volunteerism and partnering locally to enrich educational opportunities, preserve our environment and support the safety and vitality of our communities.

Read the Charitable Contributions Standard. (CR-5002S)

(Section 08)

PG&E is committed to complying with all federal, state and local laws, rules and regulations.

Section 08

Building Trust with Governments

Coworkers must comply with all requirements related to government business.

PG&E is committed to complying with all federal, state and local laws, rules and regulations. We expect coworkers to meet all legal and regulatory requirements imposed by all governmental bodies that regulate our business.

We are also fully committed to abiding by all laws governing interactions between PG&E and various governmental bodies. We respond appropriately to all government inquiries and investigations.

ENHANCED OVERSIGHT AND ENFORCEMENT PROCESS

The Enhanced Oversight and Enforcement Processis a framework designed to make sure that PG&E meets our safety and operational commitments to better serve our customers and communities. Reporting systemic safety issues for gas, electric or generation to the CPUC is a key component of the process. The focus is preventive—tracking our progress and performance to identify issues early, before they become a problem, and to correct any issues promptly if they arise.

Read the Enhanced Oversight and Enforcement Process Policy (GOV-11) and the GOV-CPUC Enhanced Oversight and Enforcement Process Standard. (GOV-1041S)

What is the Enhanced Oversight and Enforcement Process? 

The Enhanced Oversight and Enforcement Process was established by the CPUC and outlines a six-step process of escalating CPUC oversight and enforcement measures based on specific Triggering Events (PG&E refers to these as Compliance Events).

What is my role in the Enhanced Oversight and Enforcement Process? 

It is critical that we work with integrity, meet our compliance commitments and protect public, coworkerand contractor safety. That means doing your day-to-day job well and following all regulatory and internal requirements.  

The Enhanced Oversight and Enforcement Process underscores our virtues of being trustworthy and owners. If you see something that doesn’t feel right, speak up. Help to identify potential safety and operational issues early so that we can address them. We need everyone’s engagement to stay safe and compliant. This will help us improve our safety and operational outcomes and enable us to better serve our customers. Report safety issues to the Corrective Action Program (CAP), any Event Owner or Business Lead, or contact enhancedoversightquestions@pge.com. Read more about reporting safety issues in the Speak Up, Listen Up, Follow Up section of this Code.

PARTICIPATING IN THE POLITICAL PROCESS

PG&E encourages coworkers to be informed voters and become involved in the political process. As a coworker you must make it clear that any contributions you make, views you may express or activities you undertake are your own and not those of PG&E. If you choose to contribute or participate, your contributions must be on a personal basis, using your own time and funds. Participation in company-approved political action committees is voluntary.

PG&E will not reimburse you for any contribution of money donated or time spent by you on that activity.

Serving in federal, state or local government

If you seek election or appointment to a public office while employed by PG&E, contact PoliticalCompliance@pge.com to seek guidance regarding potential conflicts of interest and how those issues should be addressed.

INTERACTING WITH PUBLIC OFFICIALS

The California Public Utilities Commission, Federal Energy Regulatory Commission and other state and federal agencies have rules that restrict and require disclosure of certain communications with decision makers about issues in proceedings before those agencies. All communications with regulatory personnel must also be truthful and accurate. Ex parte communications (see definition below), in particular, are strictly regulated.

When engaging in communications with regulatory agencies, PG&E coworkers and agents are expected to seek guidance from the Law Department or Regulatory Affairs and follow PG&E policies and standards.

Read our Ex Parte CPUC Communications Procedure. (CR-2001P-06)

What denotes a public official?

A public official is any government employee or representative, including elected or appointed officials in foreign, federal, state and local governments, regulatory commissions and other oversight agencies.

What is an ex parte communication?

An ex parte communication is a communication between a decision maker and an interested person concerning an issue in a formal proceeding that does not occur on the record. Ex parte communications can occur when information is not shared in a public forum or is kept out of the record of the proceeding.

DOING BUSINESS WITH THE GOVERNMENT

We are proud to provide services to the United States federal government and state and local government entities. As a federal contractor, we must comply with a number of laws, regulations

and contractual requirements that are unique. Many of these requirements are different from and more restrictive than requirements in the commercial marketplace.

An example of these restrictive requirements is when certain government officials visit, we may not be able to provide them with common business courtesies, like a bottle of water or a meal.

Coworkers must comply with all requirements related to government business:

We always act with integrity and communicate honestly.

Fraudulent or dishonest acts in fulfilling a government contract can trigger severe penalties under the False Claims Act, including fines and jail sentences.

This includes making false statements or representations, submitting false claims or charging for hours not worked.

As a federal contractor, Pacific Gas and Electric Company has certain obligations that we must meet. Our existing policies meet U.S. government standards, including a zero-tolerance policy on human trafficking, procuring commercial sex acts and using forced labor.

Any coworker who violates these policies may be subject to disciplinary action or termination of employment. These policies apply to consultants, contractors and subcontractors working with or for Pacific Gas and Electric Company. As these are also government policies, the government may remove us from a contract if we violate these provisions. Government contracts may also have other special provisions and reporting requirements.

Be aware of those special provisions and immediately contact the Ethics & Compliance Department if any questions arise.

For more information, refer to our Federal Contract Compliance Program Charter (GOV-1028S) andFederal Government Contracts Compliance Standard. (RISK-4201S)

Political contributions and gifting

The rules surrounding providing items of value to federal, state and local government officers, officials and employees may be more restrictive than PG&E’s gift policy. Contact the State and Regulatory Affairs Compliance, Risk and Operations team to receive advance approval for all contributions (monetary and in-kind) or gifts (including food and beverages) made to government officers, officials or employees on behalf of PG&E.

For more information, refer to our Conflicts of Interest Standard. (CDT-1001S)

Lobbying

Direct lobbying or similar political activity on behalf of PG&E may be done only by coworkers who are properly registered and who are specifically approved by State and Regulatory Affairs and/or Federal Affairs. Contact PoliticalCompliance@pge.com with any questions.

For more information, refer to our Federal, State, and Local Lobbying Standard. (CR-1003S)

Disclosures and public communications

PG&E Corporation and Pacific Gas and Electric Company must comply with federal laws and regulations that require the disclosure of certain information related to Securities and Exchange Commission (SEC) filings. If you are asked to review a draft SEC report, respond promptly to help ensure that the SEC reports, other public disclosures, and the information contained within, are full, fair, timely, accurate, understandable and complete.

AS A PG&E COWORKER—

I will understand the laws and regulations applicable to my job, including specific rules related to government contracting or interacting with governmental bodies.

As a federal contractor, we must comply with a number of laws, regulations, and contractual requirements that are unique.

(Index)

INDEX

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(Policies and Standards)

PG&E POLICIES AND STANDARDS

See below for a list of policies and standards referenced in the PG&E Code of Conduct.

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(Back cover)

[PG&E logo]

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	PG&E AR Facility, LLC	DE	PG&E AR Facility, LLC

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-236629-01 on Form S-3, Registration Statement No. 333-253630-01 on Form S-3/ASR, and Registration Statement Nos. 333-176090, 333-195902, 333-206457, 333-239544, and 333-256896 on Form S-8 of our reports dated February 22, 2023, relating to the financial statements of PG&E Corporation and the effectiveness of PG&E Corporation’s internal control over financial reporting appearing in this Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2022.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-236629 on Form S-3 and Registration Statement No. 333-253630 on Form S-3/ASR of our reports dated February 22, 2023, relating to the financial statements of Pacific Gas and Electric Company and the effectiveness of Pacific Gas and Electric Company’s internal control over financial reporting appearing in this Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2022.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

EX-24

EXHIBIT 24

POWER OF ATTORNEY

Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints JOHN R. SIMON, BRIAN M. WONG, SUJATA PAGEDAR, J. ELLEN CONTI, LISA CRAWFORD, and JENNY KAN, 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, 2021 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 22nd day of February 2023.

/s/ RAJAT BAHRI	/s/ ARNO L. HARRIS
Rajat Bahri	Arno L. Harris
/s/ CHERYL F. CAMPBELL	/s/ CARLOS M. HERNANDEZ
Cheryl F. Campbell	Carlos M. Hernandez
/s/ KERRY W. COOPER	/s/ MICHAEL R. NIGGLI
Kerry W. Cooper	Michael R. Niggli
/s/ JESSICA L. DENECOUR	/s/ WILLIAM L. SMITH
Jessica L. Denecour	William L. Smith
/s/ MARK E. FERGUSON, III	/s/ BENJAMIN F. WILSON
Mark E. Ferguson, III	Benjamin F. Wilson
/s/ ROBERT C. FLEXON
Robert C. Flexon
/s/ W. CRAIG FUGATE
W. Craig Fugate

POWER OF ATTORNEY

Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints JOHN R. SIMON, BRIAN M. WONG, SUJATA PAGEDAR, J. ELLEN CONTI, LISA CRAWFORD, and JENNY KAN, 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, 2021 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 22nd day of February 2023.

/s/ RAJAT BAHRI	/s/ ARNO L. HARRIS
Rajat Bahri	Arno L. Harris
/s/ CHERYL F. CAMPBELL	/s/ CARLOS M. HERNANDEZ
Cheryl F. Campbell	Carlos M. Hernandez
/s/ KERRY W. COOPER	/s/ MICHAEL R. NIGGLI
Kerry W. Cooper	Michael R. Niggli
/s/ JESSICA L. DENECOUR	/s/ PATRICIA K. POPPE
Jessica L. Denecour	Patricia K. Poppe
/s/ MARK E. FERGUSON, III	/s/ WILLIAM L. SMITH
Mark E. Ferguson, III	William L. Smith
/s/ ROBERT C. FLEXON	/s/ BENJAMIN F. WILSON
Robert C. Flexon	Benjamin F. Wilson
/s/ W. CRAIG FUGATE	/s/ ADAM L. WRIGHT
W. Craig Fugate	Adam L. Wright

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Patricia K. Poppe, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ PATRICIA K. POPPE
	Patricia K. Poppe
	Chief Executive Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Christopher A. Foster, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ CHRISTOPHER A. FOSTER
	Christopher A. Foster
	Executive Vice President and Chief Financial Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Adam L. Wright, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ ADAM L. WRIGHT
	Adam L. Wright
	Executive Vice President, Operations and Chief Operating Officer

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Marlene M. Santos, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ MARLENE M. SANTOS
	Marlene M. Santos
	Executive Vice President and Chief Customer Officer

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Jason M. Glickman, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ JASON M. GLICKMAN
	Jason M. Glickman
	Executive Vice President, Engineering, Planning, and Strategy

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Stephanie N. Williams, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2022 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 22, 2023	/s/ STEPHANIE N. WILLIAMS
	Stephanie N. Williams
	Vice President, Chief Financial Officer and Controller

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2022 (“Form 10-K”), I, Patricia K. Poppe, Chief Executive 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.

/s/ PATRICIA K. POPPE

Patricia K. Poppe

Chief Executive Officer

February 22, 2023

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2022 (“Form 10-K”), I, Christopher A. Foster, Executive 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.

/s/ CHRISTOPHER A. FOSTER

Christopher A. Foster

Executive Vice President and Chief Financial Officer

February 22, 2023

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2022 (“Form 10-K”), I, Adam L. Wright, Executive Vice President, Operations and Chief Operating Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ ADAM L. WRIGHT

Adam L. Wright

Executive Vice President, Operations and Chief Operating Officer

February 22, 2023

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2022 (“Form 10-K”), I, Marlene M. Santos, Executive Vice President and Chief Customer Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)the Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ MARLENE M. SANTOS

Marlene M. Santos

Executive Vice President and Chief Customer Officer

February 22, 2023

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2022 (“Form 10-K”), I, Jason M. Glickman, Executive Vice President, Engineering, Planning, and Strategy 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.

/s/ JASON M. GLICKMAN

Jason M. Glickman

Executive Vice President, Engineering, Planning, and Strategy

February 22, 2023

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2022 (“Form 10-K”), I, Stephanie N. Williams, 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.

/s/ STEPHANIE N. WILLIAMS

Stephanie N. Williams

Vice President, Chief Financial Officer and Controller

February 22, 2023

XML

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Firm ID	34
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	San Francisco, California

XML

Cover Page - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Feb. 16, 2023

Jun. 30, 2022

Document Type

10-K

Document Annual Report

true

Current Fiscal Year End Date

--12-31

Document Period End Date

Dec. 31, 2022

Document Transition Report

false

Entity File Number

1-12609

Entity Incorporation, State or Country Code

CA

Entity Tax Identification Number

94-3234914

Entity Address, Address Line One

300 Lakeside Drive

Entity Address, City or Town

Oakland,

Entity Address, State or Province

CA

Entity Address, Postal Zip Code

94612

City Area Code

415

Local Phone Number

973-1000

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Bankruptcy Proceedings, Reporting Current

true

Entity Public Float

$ 20,819

Entity Common Stock, Shares Outstanding (in shares)

2,466,208,388

Documents Incorporated by Reference

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 2023 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Amendment Flag

false

Document Fiscal Year Focus

2022

Document Fiscal Period Focus

FY

Entity Registrant Name

PG&E CORP

Entity Central Index Key

0001004980

Pacific Gas & Electric Co (Utility)

Document Type

10-K

Entity File Number

1-2348

Entity Incorporation, State or Country Code

CA

Entity Tax Identification Number

94-0742640

Entity Address, Address Line One

300 Lakeside Drive

Entity Address, City or Town

Oakland,

Entity Address, State or Province

CA

Entity Address, Postal Zip Code

94612

City Area Code

415

Local Phone Number

973-1000

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Non-accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Bankruptcy Proceedings, Reporting Current

true

Entity Common Stock, Shares Outstanding (in shares)

264,374,809

Documents Incorporated by Reference

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 2023 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Entity Registrant Name

PACIFIC GAS & ELECTRIC CO

Entity Central Index Key

0000075488

The New York Stock Exchange | Common stock, no par value

Title of 12(b) Security

Common stock, no par value

Trading Symbol

PCG

Security Exchange Name

NYSE

The New York Stock Exchange | Equity Units

Title of 12(b) Security

Equity Units

Trading Symbol

PCGU

Security Exchange Name

NYSE

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% series A redeemable

Trading Symbol

PCG-PE

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% redeemable

Trading Symbol

PCG-PD

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.80% redeemable

Trading Symbol

PCG-PG

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.50% redeemable

Trading Symbol

PCG-PH

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable

Trading Symbol

PCG-PI

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 6% nonredeemable

Trading Symbol

PCG-PA

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable

Trading Symbol

PCG-PB

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% nonredeemable

Trading Symbol

PCG-PC

Security Exchange Name

NYSEAMER

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenues
Total operating revenues	$ 21,680	$ 20,642	$ 18,469
Operating Expenses
Operating and maintenance	9,809	10,200	8,684
SB 901 securitization charges, net	608	0	0
Wildfire-related claims, net of recoveries	237	258	251
Wildfire Fund expense	477	517	413
Depreciation, amortization, and decommissioning	3,856	3,403	3,468
Total operating expenses	19,843	18,759	16,714
Operating Income	1,837	1,883	1,755
Interest income	162	20	39
Interest expense	(1,917)	(1,601)	(1,260)
Other income, net	394	457	483
Reorganization items, net	0	(11)	(1,959)
Income Before Income Taxes	476	748	(942)
Income tax provision (benefit)	(1,338)	836	362
Net Income (Loss)	1,814	(88)	(1,304)
Preferred stock dividend requirement of subsidiary	14	14	14
Income (Loss) Attributable to Common Shareholders	$ 1,800	$ (102)	$ (1,318)
Weighted Average Common Shares Outstanding, Basic (in shares)	1,987	1,985	1,257
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,132	1,985	1,257
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ 0.91	$ (0.05)	$ (1.05)
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ 0.84	$ (0.05)	$ (1.05)
Electric
Operating Revenues
Total operating revenues	$ 15,060	$ 15,131	$ 13,858
Operating Expenses
Cost of electricity and natural gas	2,756	3,232	3,116
Natural gas
Operating Revenues
Total operating revenues	6,620	5,511	4,611
Operating Expenses
Cost of electricity and natural gas	$ 2,100	$ 1,149	$ 782

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 1,814	$ (88)	$ (1,304)
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	21	7	(17)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)	(6)	0	0
Total other comprehensive income (loss)	15	7	(17)
Comprehensive Income (Loss)	1,829	(81)	(1,321)
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income (Loss) Attributable to Common Shareholders	$ 1,815	$ (95)	$ (1,335)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Pension and other postretirement benefit plans obligations, tax	$ 8	$ 3	$ 7
Net unrealized losses on available for sale securities, tax	$ 3	$ 0	$ 0

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current Assets
Cash and cash equivalents	$ 734	$ 291
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	213	16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Regulatory balancing accounts	3,264	2,999
Other	1,624	1,784
Regulatory assets	296	496
Inventories
Gas stored underground and fuel oil	91	44
Materials and supplies	751	552
Wildfire Fund asset	460	461
Other	1,433	882
Total current assets	12,815	11,077
Property, Plant, and Equipment
Electric	74,772	69,482
Gas	28,226	25,979
Construction work in progress	4,137	3,479
Financing lease and other	19	20
Total property, plant, and equipment	107,154	98,960
Accumulated depreciation	(30,946)	(29,134)
Net property, plant, and equipment	76,208	69,826
Other Noncurrent Assets
Regulatory assets	16,443	9,207
Customer credit trust	745	0
Nuclear decommissioning trusts	3,297	3,798
Operating lease right of use asset	1,311	1,234
Wildfire Fund asset	4,847	5,313
Income taxes receivable	9	9
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)	2,969	2,863
Total other noncurrent assets	29,621	22,424
TOTAL ASSETS	118,644	103,327
Current Liabilities
Short-term borrowings	2,055	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268	4,481
Accounts payable
Trade creditors	2,888	2,855
Regulatory balancing accounts	1,658	1,121
Other	778	679
Operating lease liabilities	231	468
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	626	481
Wildfire-related claims	1,912	2,722
Other	3,372	2,436
Total current liabilities	15,788	17,427
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	47,742	38,225
Regulatory liabilities	17,630	11,999
Pension and other postretirement benefits	231	860
Asset retirement obligations	5,912	5,298
Deferred income taxes	2,732	3,177
Operating lease liabilities	1,243	810
Other	4,291	4,308
Total noncurrent liabilities	79,781	64,677
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates	32,887	35,129
Treasury stock, at cost; 247,743,590 and 477,743,590 shares at respective dates	(2,517)	(4,854)
Reinvested earnings	(7,542)	(9,284)
Accumulated other comprehensive loss	(5)	(20)
Total shareholders’ equity	22,823	20,971
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	23,075	21,223
TOTAL LIABILITIES AND EQUITY	$ 118,644	$ 103,327

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	$ 213	$ 16
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268	4,481
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	626	481
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	$ 47,742	$ 38,225
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	3,600,000,000	3,600,000,000
Common stock, shares outstanding (in shares)	1,987,784,948	1,985,400,540
Treasury stock, shares at cost (in shares)	247,743,590	477,743,590
Variable Interest Entity, Primary Beneficiary
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	$ 201	$ 4
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,470	2,060
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,160	1,090
Net noncurrent accounts receivable	17	187
Noncurrent allowance for doubtful accounts	1	15
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	168	18
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	116	3
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	$ 10,310	$ 1,820

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Operating Activities
Net Income (Loss)	$ 1,814	$ (88)	$ (1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,856	3,403	3,468
Bad debt expense	143	154	150
Allowance for equity funds used during construction	(184)	(133)	(140)
Deferred income taxes and tax credits, net	(452)	1,783	1,097
Reorganization items, net	0	(73)	1,458
Wildfire Fund expense	477	517	413
Disallowed capital expenditures	15	0	17
Other	517	248	249
Effect of changes in operating assets and liabilities:
Accounts receivable	(757)	(589)	(1,182)
Wildfire-related insurance receivable	453	(723)	1,564
Inventories	(246)	(32)	6
Accounts payable	627	117	58
Wildfire-related claims	(810)	472	(16,525)
Other current assets and liabilities	17	244	(1,079)
Regulatory assets, liabilities, and balancing accounts, net	(1,131)	(2,266)	(2,451)
Liabilities subject to compromise	0	0	413
Contributions to Wildfire fund	(193)	(193)	(5,200)
Other noncurrent assets and liabilities	(425)	(579)	(142)
Net cash provided by operating activities	3,721	2,262	(19,130)
Cash Flows from Investing Activities
Capital expenditures	(9,584)	(7,689)	(7,690)
Proceeds from sale of SFGO	0	749	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	3,316	1,678	1,518
Purchases of nuclear decommissioning trust investments	(3,208)	(1,702)	(1,590)
Proceeds from sales and maturities of customer credit trust investments	250	0	0
Purchases of customer credit trust investments	(1,022)	0	0
Other	34	59	14
Net cash used in investing activities	(10,214)	(6,905)	(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	0	500
Repayments of debtor-in-possession credit facility	0	0	(2,000)
Debtor-in-possession credit facility debt issuance costs	0	0	(6)
Bridge facility financing fees	0	0	(73)
Borrowings under credit facilities	10,130	9,730	8,554
Repayments under credit facilities	(9,750)	(9,976)	(3,949)
Credit facilities financing fees	0	(9)	(22)
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates	0	300	1,448
Short-term debt matured	(300)	(1,450)	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $178 at respective dates	4,271	4,624	13,497
Repayment of long-term debt	(5,968)	(87)	(764)
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates	312	0	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	0	370	0
Exchanged debt financing fees	0	0	(103)
Common stock issued	0	0	7,582
Equity Units issued	0	0	1,304
Other	53	(29)	(40)
Net cash provided by financing activities	7,133	4,323	25,928
Net change in cash, cash equivalents, and restricted cash	640	(320)	(950)
Cash, cash equivalents, and restricted cash at January 1	307	627	1,577
Cash, cash equivalents, and restricted cash at December 31	947	307	627
Less: Restricted cash and restricted cash equivalents	(213)	(16)	(143)
Cash and cash equivalents at December 31	734	291	484
Cash received (paid) for:
Interest, net of amounts capitalized	(1,607)	(1,404)	(1,563)
Income taxes, net	0	99	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,174	1,311	515
Operating lease liabilities arising from obtaining ROU assets	529	100	13
Common stock issued in satisfaction of liabilities	0	0	8,276
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	(2,337)	4,854	0
SB 901 Securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	7,464	0	0
Repayments of recovery bonds	(33)	0	0
Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	972	850	0
Repayments of recovery bonds	$ (18)	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Financing Activities
Issuance costs for short-term debt	$ 0	$ 1	$ 2
Premium, discount, and issuance costs on proceeds from long-term debt	29	33	178
Performance based incentives earned	38	0	0
SB 901 Securitization
Cash Flows from Financing Activities
Financing fees	36	0	0
Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Financing fees	$ 11	$ 10	$ 0

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CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions		Total	PG&E ShareCo Common Stock	Total Shareholders' Equity	Common Stock		Treasury Stock	Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)	Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance (in shares) at Dec. 31, 2019					529,236,741
Beginning balance at Dec. 31, 2019		$ 5,388		$ 5,136	$ 13,038			$ (7,892)	$ (10)	$ 252
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)		(1,304)		(1,304)				(1,304)
Other comprehensive income (loss)		(17)		(17)					(17)
Common stock issued, net (in shares)					1,455,441,932
Common stock issued, net		15,854		15,854	$ 15,854
Equity units issued		1,304		1,304	1,304
Stock-based compensation amortization		28		28	$ 28
Ending balance (in shares) at Dec. 31, 2020					1,984,678,673
Ending balance at Dec. 31, 2020		21,253		21,001	$ 30,224		$ 0	(9,196)	(27)	252
Ending balance, treasury (in shares) at Dec. 31, 2020							0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)		(88)		(88)				(88)
Other comprehensive income (loss)		7		7					7
Common stock issued, net (in shares)			477,743,590		721,867	[1]
Common stock issued, net	[1]	4,854		4,854	$ 4,854
Treasury stock acquired (in shares)							477,743,590
Treasury stock acquired		(4,854)		(4,854)			$ (4,854)
Stock-based compensation amortization		$ 51		51	$ 51
Ending balance (in shares) at Dec. 31, 2021		1,985,400,540			1,985,400,540
Ending balance at Dec. 31, 2021		$ 21,223		20,971	$ 35,129		$ (4,854)	(9,284)	(20)	252
Ending balance, treasury (in shares) at Dec. 31, 2021		477,743,590					477,743,590
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)		$ 1,814		1,814				1,814
Other comprehensive income (loss)		15		15					15
Common stock issued, net (in shares)					2,384,408
Common stock issued, net		(2,337)		(2,337)	$ (2,337)
Treasury stock disposition (in shares)							(230,000,000)
Treasury stock disposition		2,337		2,337			$ 2,337
Stock-based compensation amortization		95		95	$ 95
Preferred stock dividend requirement of subsidiary in arrears		(59)		(59)				(59)
Preferred stock dividend requirement of subsidiary		$ (13)		(13)				(13)
Ending balance (in shares) at Dec. 31, 2022		1,987,784,948			1,987,784,948
Ending balance at Dec. 31, 2022		$ 23,075		$ 22,823	$ 32,887		$ (2,517)	$ (7,542)	$ (5)	$ 252
Ending balance, treasury (in shares) at Dec. 31, 2022		247,743,590					247,743,590

[1] Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K .

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CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Revenues
Total operating revenues	$ 21,680.0	$ 20,642.0	$ 18,469.0
Operating Expenses
Operating and maintenance	9,809.0	10,200.0	8,684.0
SB 901 securitization charges, net	608.0	0.0	0.0
Wildfire-related claims, net of recoveries	237.0	258.0	251.0
Wildfire Fund expense	477.0	517.0	413.0
Depreciation, amortization, and decommissioning	3,856.0	3,403.0	3,468.0
Total operating expenses	19,843.0	18,759.0	16,714.0
Operating Income	1,837.0	1,883.0	1,755.0
Interest income	162.0	20.0	39.0
Interest expense	(1,917.0)	(1,601.0)	(1,260.0)
Other income, net	394.0	457.0	483.0
Reorganization items, net	0.0	(11.0)	(1,959.0)
Income Before Income Taxes	476.0	748.0	(942.0)
Income tax provision (benefit)	(1,338.0)	836.0	362.0
Net Income (Loss)	1,814.0	(88.0)	(1,304.0)
Preferred stock dividend requirement	13.0
Income (Loss) Attributable to Common Shareholders	1,800.0	(102.0)	(1,318.0)
Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	21,680.0	20,642.0	18,469.0
Operating Expenses
Operating and maintenance	9,725.0	10,194.0	8,707.0
SB 901 securitization charges, net	608.0	0.0	0.0
Wildfire-related claims, net of recoveries	237.0	258.0	251.0
Wildfire Fund expense	477.0	517.0	413.0
Depreciation, amortization, and decommissioning	3,856.0	3,403.0	3,469.0
Total operating expenses	19,759.0	18,753.0	16,738.0
Operating Income	1,921.0	1,889.0	1,731.0
Interest income	162.0	22.0	39.0
Interest expense	(1,658.0)	(1,373.0)	(1,111.0)
Other income, net	595.0	512.0	470.0
Reorganization items, net	0.0	(12.0)	(310.0)
Income Before Income Taxes	1,020.0	1,038.0	819.0
Income tax provision (benefit)	(1,206.0)	900.0	408.0
Net Income (Loss)	2,226.0	138.0	411.0
Preferred stock dividend requirement	14.0	14.0	14.0
Income (Loss) Attributable to Common Shareholders	2,212.0	124.0	397.0
Electric
Operating Revenues
Total operating revenues	15,060.0	15,131.0	13,858.0
Operating Expenses
Cost of electricity and natural gas	2,756.0	3,232.0	3,116.0
Electric | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	15,060.0	15,131.0	13,858.0
Operating Expenses
Cost of electricity and natural gas	2,756.0	3,232.0	3,116.0
Natural gas
Operating Revenues
Total operating revenues	6,620.0	5,511.0	4,611.0
Operating Expenses
Cost of electricity and natural gas	2,100.0	1,149.0	782.0
Natural gas | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	6,620.0	5,511.0	4,611.0
Operating Expenses
Cost of electricity and natural gas	$ 2,100.0	$ 1,149.0	$ 782.0

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net Income (Loss)	$ 1,814	$ (88)	$ (1,304)
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates)	21	7	(17)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)	(6)	0	0
Total other comprehensive income (loss)	15	7	(17)
Comprehensive Income (Loss)	1,829	(81)	(1,321)
Pacific Gas & Electric Co (Utility)
Net Income (Loss)	2,226	138	411
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates)	6	(4)	(6)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)	(5)	0	0
Total other comprehensive income (loss)	1	(4)	(6)
Comprehensive Income (Loss)	$ 2,227	$ 134	$ 405

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension and other postretirement benefit plans obligations, tax	$ 8	$ 3	$ 7
Net unrealized losses on available for sale securities, tax	3	0	0
Pacific Gas & Electric Co (Utility)
Pension and other postretirement benefit plans obligations, tax	2	1	2
Net unrealized losses on available for sale securities, tax	$ 3	$ 0	$ 0

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CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current Assets
Cash and cash equivalents	$ 734	$ 291
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	213	16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Regulatory balancing accounts	3,264	2,999
Other	1,624	1,784
Regulatory assets	296	496
Inventories
Gas stored underground and fuel oil	91	44
Materials and supplies	751	552
Wildfire Fund asset	460	461
Other	1,433	882
Total current assets	12,815	11,077
Property, Plant, and Equipment
Electric	74,772	69,482
Gas	28,226	25,979
Construction work in progress	4,137	3,479
Financing lease	19	20
Total property, plant, and equipment	107,154	98,960
Accumulated depreciation	(30,946)	(29,134)
Net property, plant, and equipment	76,208	69,826
Other Noncurrent Assets
Regulatory assets	16,443	9,207
Customer credit trust	745	0
Nuclear decommissioning trusts	3,297	3,798
Operating lease right of use asset	1,311	1,234
Wildfire Fund asset	4,847	5,313
Income taxes receivable	9	9
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)	2,969	2,863
Total other noncurrent assets	29,621	22,424
TOTAL ASSETS	118,644	103,327
Current Liabilities
Short-term borrowings	2,055	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268	4,481
Accounts payable
Trade creditors	2,888	2,855
Regulatory balancing accounts	1,658	1,121
Other	778	679
Operating lease liabilities	231	468
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	626	481
Wildfire-related claims	1,912	2,722
Other	3,372	2,436
Total current liabilities	15,788	17,427
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	47,742	38,225
Regulatory liabilities	17,630	11,999
Pension and other postretirement benefits	231	860
Asset retirement obligations	5,912	5,298
Deferred income taxes	2,732	3,177
Operating lease liabilities	1,243	810
Other	4,291	4,308
Total noncurrent liabilities	79,781	64,677
Shareholders’ Equity
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	32,887	35,129
Reinvested earnings	(7,542)	(9,284)
Accumulated other comprehensive loss	(5)	(20)
Total shareholders’ equity	22,823	20,971
TOTAL LIABILITIES AND EQUITY	118,644	103,327
Pacific Gas & Electric Co (Utility)
Current Assets
Cash and cash equivalents	609	165
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	213	16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Regulatory balancing accounts	3,264	2,999
Other	1,633	1,932
Regulatory assets	296	496
Inventories
Gas stored underground and fuel oil	91	44
Materials and supplies	751	552
Wildfire Fund asset	460	461
Other	1,421	869
Total current assets	12,687	11,086
Property, Plant, and Equipment
Electric	74,772	69,482
Gas	28,226	25,979
Construction work in progress	4,137	3,480
Financing lease	18	18
Total property, plant, and equipment	107,153	98,959
Accumulated depreciation	(30,946)	(29,131)
Net property, plant, and equipment	76,207	69,828
Other Noncurrent Assets
Regulatory assets	16,443	9,207
Customer credit trust	745	0
Nuclear decommissioning trusts	3,297	3,798
Operating lease right of use asset	1,311	1,232
Wildfire Fund asset	4,847	5,313
Income taxes receivable	7	7
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)	2,834	2,706
Total other noncurrent assets	29,484	22,263
TOTAL ASSETS	118,378	103,177
Current Liabilities
Short-term borrowings	2,055	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,241	4,455
Accounts payable
Trade creditors	2,886	2,853
Regulatory balancing accounts	1,658	1,121
Other	747	648
Operating lease liabilities	231	467
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	573	430
Wildfire-related claims	1,912	2,722
Other	3,067	2,430
Total current liabilities	15,370	17,310
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	43,155	33,632
Regulatory liabilities	17,630	11,999
Pension and other postretirement benefits	160	764
Asset retirement obligations	5,912	5,298
Deferred income taxes	3,090	3,409
Operating lease liabilities	1,243	810
Other	4,334	4,345
Total noncurrent liabilities	75,524	60,257
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	29,280	28,286
Reinvested earnings	(3,368)	(4,247)
Accumulated other comprehensive loss	(8)	(9)
Total shareholders’ equity	27,484	25,610
TOTAL LIABILITIES AND EQUITY	$ 118,378	$ 103,177

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	$ 213	$ 16
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268	4,481
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	626	481
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	$ 47,742	$ 38,225
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	3,600,000,000	3,600,000,000
Common stock, shares outstanding (in shares)	1,987,784,948	1,985,400,540
Pacific Gas & Electric Co (Utility)
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	$ 213	$ 16
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,645	2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,304	1,207
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,241	4,455
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	573	430
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	$ 43,155	$ 33,632
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	264,374,809	264,374,809
Variable Interest Entity, Primary Beneficiary
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	$ 201	$ 4
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,470	2,060
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,160	1,090
Net noncurrent accounts receivable	17	187
Noncurrent allowance for doubtful accounts	1	15
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	168	18
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	116	3
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	10,310	1,820
Variable Interest Entity, Primary Beneficiary | Pacific Gas & Electric Co (Utility)
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)	201	4
Allowance for doubtful accounts	166	171
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)	2,470	2,060
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)	1,160	1,090
Net noncurrent accounts receivable	17	187
Noncurrent allowance for doubtful accounts	1	15
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	168	18
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)	116	3
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)	$ 10,310	$ 1,820

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CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Operating Activities
Net Income (Loss)	$ 1,814	$ (88)	$ (1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,856	3,403	3,468
Bad debt expense	143	154	150
Allowance for equity funds used during construction	(184)	(133)	(140)
Deferred income taxes and tax credits, net	(452)	1,783	1,097
Reorganization items, net	0	(73)	1,458
Wildfire Fund expense	477	517	413
Disallowed capital expenditures	15	0	17
Other	517	248	249
Effect of changes in operating assets and liabilities:
Accounts receivable	(757)	(589)	(1,182)
Wildfire-related insurance receivable	453	(723)	1,564
Inventories	(246)	(32)	6
Accounts payable	627	117	58
Wildfire-related claims	(810)	472	(16,525)
Other current assets and liabilities	17	244	(1,079)
Regulatory assets, liabilities, and balancing accounts, net	(1,131)	(2,266)	(2,451)
Liabilities subject to compromise	0	0	413
Contributions to Wildfire fund	(193)	(193)	(5,200)
Other noncurrent assets and liabilities	(425)	(579)	(142)
Net cash provided by operating activities	3,721	2,262	(19,130)
Cash Flows from Investing Activities
Capital expenditures	(9,584)	(7,689)	(7,690)
Proceeds from sale of SFGO	0	749	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	3,316	1,678	1,518
Purchases of nuclear decommissioning trust investments	(3,208)	(1,702)	(1,590)
Proceeds from sales and maturities of customer credit trust investments	250	0	0
Purchases of customer credit trust investments	(1,022)	0	0
Other	34	59	14
Net cash used in investing activities	(10,214)	(6,905)	(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	0	500
Repayments of debtor-in-possession credit facility	0	0	(2,000)
Debtor-in-possession credit facility debt issuance costs	0	0	(6)
Bridge facility financing fees	0	0	(73)
Borrowings under credit facilities	10,130	9,730	8,554
Repayments under credit facilities	(9,750)	(9,976)	(3,949)
Credit facilities financing fees	0	(9)	(22)
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates	0	300	1,448
Short-term debt matured	(300)	(1,450)	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $88 at respective dates	4,271	4,624	13,497
Repayments of long-term debt	(5,968)	(87)	(764)
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates	312	0	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	0	370	0
Exchanged debt financing fees	0	0	(103)
Other	53	(29)	(40)
Net cash provided by financing activities	7,133	4,323	25,928
Net change in cash, cash equivalents, and restricted cash	640	(320)	(950)
Cash, cash equivalents, and restricted cash at January 1	307	627	1,577
Cash, cash equivalents, and restricted cash at December 31	947	307	627
Less: Restricted cash and restricted cash equivalents	(213)	(16)	(143)
Cash and cash equivalents at December 31	734	291	484
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(1,607)	(1,404)	(1,563)
Income taxes, net	0	99	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,174	1,311	515
Operating lease liabilities arising from obtaining ROU assets	529	100	13
SB 901 Securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	7,464	0	0
Repayments of recovery bonds	(33)	0	0
Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	972	850	0
Repayments of recovery bonds	(18)	0	0
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net Income (Loss)	2,226	138	411
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,856	3,403	3,469
Bad debt expense	143	154	150
Allowance for equity funds used during construction	(184)	(133)	(140)
Deferred income taxes and tax credits, net	(319)	1,846	1,141
Reorganization items, net	0	(41)	(90)
Wildfire Fund expense	477	517	413
Disallowed capital expenditures	15	0	17
Other	102	172	220
Effect of changes in operating assets and liabilities:
Accounts receivable	(763)	(584)	(1,160)
Wildfire-related insurance receivable	453	(723)	1,564
Inventories	(246)	(32)	6
Accounts payable	627	44	(24)
Wildfire-related claims	(810)	472	(16,525)
Other current assets and liabilities	16	251	(1,141)
Regulatory assets, liabilities, and balancing accounts, net	(1,131)	(2,266)	(2,451)
Liabilities subject to compromise	0	0	401
Contributions to Wildfire fund	(193)	(193)	(5,200)
Other noncurrent assets and liabilities	(438)	(577)	(108)
Net cash provided by operating activities	3,831	2,448	(19,047)
Cash Flows from Investing Activities
Capital expenditures	(9,584)	(7,689)	(7,690)
Proceeds from sale of SFGO	0	749	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	3,316	1,678	1,518
Purchases of nuclear decommissioning trust investments	(3,208)	(1,702)	(1,590)
Proceeds from sales and maturities of customer credit trust investments	250	0	0
Purchases of customer credit trust investments	(1,022)	0	0
Proceeds from (repayments of) intercompany note to PG&E Corporation	145	(145)	0
Other	34	59	14
Net cash used in investing activities	(10,069)	(7,050)	(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	0	500
Repayments of debtor-in-possession credit facility	0	0	(2,000)
Debtor-in-possession credit facility debt issuance costs	0	0	(6)
Bridge facility financing fees	0	0	(33)
Borrowings under credit facilities	10,130	9,730	8,554
Repayments under credit facilities	(9,750)	(9,976)	(3,949)
Credit facilities financing fees	0	(9)	(22)
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates	0	300	1,448
Short-term debt matured	(300)	(1,450)	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $88 at respective dates	4,271	4,624	8,837
Repayments of long-term debt	(5,941)	(59)	(100)
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates	312	0	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	0	370	0
Exchanged debt financing fees	0	0	(103)
Preferred stock dividends paid	(70)	0	0
Common stock dividends paid	(1,275)	0	0
Equity contribution from PG&E Corporation	994	0	12,986
Other	123	(1)	(42)
Net cash provided by financing activities	6,879	4,379	26,070
Net change in cash, cash equivalents, and restricted cash	641	(223)	(725)
Cash, cash equivalents, and restricted cash at January 1	181	404	1,129
Cash, cash equivalents, and restricted cash at December 31	822	181	404
Less: Restricted cash and restricted cash equivalents	(213)	(16)	(143)
Cash and cash equivalents at December 31	609	165	261
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(1,374)	(1,198)	(1,458)
Income taxes, net	0	99	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,174	1,311	515
Operating lease liabilities arising from obtaining ROU assets	529	100	13
Common stock equity infusion from PG&E Corporation used to satisfy liabilities	0	0	6,750
Pacific Gas & Electric Co (Utility) | SB 901 Securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	7,464	0	0
Repayments of recovery bonds	(33)	0	0
Pacific Gas & Electric Co (Utility) | Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds	972	850	0
Repayments of recovery bonds	$ (18)	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Financing Activities
Issuance costs for short-term debt	$ 0	$ 1	$ 2
Premium, discount, and issuance costs on proceeds from long-term debt	29	33	178
Performance based incentives earned	38	0	0
SB 901 Securitization
Cash Flows from Financing Activities
Financing fees	36	0	0
Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Financing fees	11	10	0
Pacific Gas & Electric Co (Utility)
Cash Flows from Financing Activities
Issuance costs for short-term debt	0	1	2
Premium, discount, and issuance costs on proceeds from long-term debt	29	33	88
Performance based incentives earned	38	0	0
Pacific Gas & Electric Co (Utility) | SB 901 Securitization
Cash Flows from Financing Activities
Financing fees	36	0	0
Pacific Gas & Electric Co (Utility) | Series 2022-A Recovery Bonds
Cash Flows from Financing Activities
Financing fees	$ 11	$ 10	$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY, UTILITY - USD ($) $ in Millions	Total	Pacific Gas & Electric Co (Utility)	Total Shareholders' Equity	Total Shareholders' Equity Pacific Gas & Electric Co (Utility)	Preferred Stock Pacific Gas & Electric Co (Utility)	Common Stock	Common Stock Pacific Gas & Electric Co (Utility)	Additional Paid-in Capital Pacific Gas & Electric Co (Utility)	Reinvested Earnings	Reinvested Earnings Pacific Gas & Electric Co (Utility)	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Pacific Gas & Electric Co (Utility)
Beginning balance at Dec. 31, 2019	$ 5,388		$ 5,136	$ 5,335	$ 258	$ 13,038	$ 1,322	$ 8,550	$ (7,892)	$ (4,796)	$ (10)	$ 1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(1,304)	$ 411	(1,304)	411					(1,304)	411
Other comprehensive income (loss)	(17)	(6)	(17)	(6)							(17)	(6)
Equity contribution				19,736				19,736
Ending balance at Dec. 31, 2020	21,253		21,001	25,476	258	30,224	1,322	28,286	(9,196)	(4,385)	(27)	(5)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(88)	138	(88)	138					(88)	138
Other comprehensive income (loss)	7	(4)	7	(4)							7	(4)
Ending balance at Dec. 31, 2021	21,223		20,971	25,610	258	35,129	1,322	28,286	(9,284)	(4,247)	(20)	(9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	1,814	2,226	1,814	2,226					1,814	2,226
Other comprehensive income (loss)	15	1	15	1							15	1
Equity contribution				994				994
Preferred stock dividend requirement of subsidiary in arrears	(59)		(59)	(59)					(59)	(59)
Preferred stock dividend requirement		$ (11)		(13)						(13)
Common stock dividend				(1,275)						(1,275)
Ending balance at Dec. 31, 2022	$ 23,075		$ 22,823	$ 27,484	$ 258	$ 32,887	$ 1,322	$ 29,280	$ (7,542)	$ (3,368)	$ (5)	$ (8)

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ORGANIZATION AND BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION AND BASIS OF PRESENTATION

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 assess financial 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, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan 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, results of operations, liquidity, and cash flows during the period in which such change occurred.

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BANKRUPTCY FILING

12 Months Ended

Dec. 31, 2022

Reorganizations [Abstract]

BANKRUPTCY FILING

BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Ad Hoc Committee of Holders of Trade Claims (the “Trade Committee”). The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On September 12, 2022, the Utility filed a petition for en banc review, which was denied on October 5, 2022. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the post-petition interest matter, but the amount of that loss is not reasonably estimable at this time. If the Ninth Circuit Court of Appeals decision is not reversed, then the matter would be remanded to the Bankruptcy Court to evaluate the rate of interest for each individual contract, the conditions under which the contract rate applies, and whether payment of interest under state law would be warranted for each contract and claimant. These proceedings therefore will require extensive discovery and motion practice before the Bankruptcy Court with respect to each of these claims on a variety of contractual issues and equitable considerations. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings or any further appeals.

Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.

Unresolved Chapter 11 Claims

PG&E Corporation and the Utility have received over 100,000 proofs of claim since January 29, 2019, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and the Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims, including asserted litigation claims, trade creditor claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets.

Holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 15 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 15 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims that were subject to certain defenses which allowed PG&E Corporation and the Utility to file objections expunging those claims on an omnibus basis, PG&E Corporation and the Utility are working to resolve disputed claims, including Subordinated Debt Claims and HoldCo Rescission or Damage Claims. By order of the Bankruptcy Court, the current deadline for PG&E Corporation and the Utility to object to claims is June 20, 2023.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 through 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.

Cash, Cash Equivalents, and Restricted Cash

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. As of December 31, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

Revenue Recognition

Revenue from Contracts with Customers

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. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. 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, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. 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. As a result, these differences have no impact on net income.

The following table presents the Utility’s revenues disaggregated by type of customer:

	Year Ended December 31,
(in millions)	2022		2021
Electric
Revenue from contracts with customers
Residential	$	6,130	$	6,089
Commercial	5,416		5,042
Industrial	1,626		1,493
Agricultural	1,830		1,565
Public street and highway lighting	77		73
Other, net (1)	(247)		(84)
Total revenue from contracts with customers - electric	14,832		14,178
Regulatory balancing accounts (2)	228		953
Total electric operating revenue	$	15,060	$	15,131
Natural gas
Revenue from contracts with customers
Residential	$	3,353	$	2,759
Commercial	1,005		713
Transportation service only	1,534		1,346
Other, net (1)	163		140
Total revenue from contracts with customers - gas	6,055		4,958
Regulatory balancing accounts (2)	565		553
Total natural gas operating revenue	6,620		5,511
Total operating revenues	$	21,680	$	20,642

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022.

PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of December 31, 2022, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

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.

Inventories

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, 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.

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

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2022		2021
Electricity generating facilities (1)	5 to 75	$	11,781	$	11,217
Electricity distribution facilities	10 to 70	41,061		37,723
Electricity transmission facilities	15 to 75	16,413		15,516
Natural gas distribution facilities	20 to 60	15,366		14,100
Natural gas transmission and storage facilities	5 to 66	9,859		9,067
Financing lease		18		18
Construction work in progress		4,137		3,480
General plant and other	5 to 50	8,518		7,838
Total property, plant, and equipment		107,153		98,959
Accumulated depreciation		(30,946)		(29,131)
Net property, plant, and equipment (2)		$	76,207	$	69,828

(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 16 below.

(2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 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, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020.  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 cost 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 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 $81 million and $184 million during 2022, $56 million and $133 million during 2021, and $35 million and $140 million during 2020.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations:

(in millions)	2022		2021
ARO liability at beginning of year	$	5,298	$	6,412
Liabilities incurred	134		—
Revision in estimated cash flows	325		(1,378)
Accretion	213		287
Liabilities settled	(58)		(23)
ARO liability at end of year	$	5,912	$	5,298

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. For more information, see Note 4 below.

The Utility has not recorded a liability related to certain AROs 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, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 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 through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020.

The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022.

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.

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 through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its debt 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 to or recoverable from, respectively, 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.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred.

Senate Bill 846

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE's Civil Nuclear Credit Program” below). Under the loan agreement, the DWR will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements.

U.S. DOE’s Civil Nuclear Credit Program

On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense on the Consolidated Statements of Income as eligible costs are incurred.

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.  

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below.

Non-Consolidated VIEs

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 as of December 31, 2022, 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 or 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 as of December 31, 2022, it did not consolidate any of them.

Contributions to the Wildfire Fund Established Pursuant to AB 1054

PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

PG&E Corporation and the Utility evaluate and, where appropriate, update all assumptions quarterly. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire. During the year ended December 31, 2022, PG&E Corporation and the Utility updated assumptions related to the mitigation effectiveness and historical fire loss dataset to align with the risk modeling within the 2022 WMP. These updates did not change the estimated period of coverage, which continues to be 15 years from the inception of the Wildfire Fund.

As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in Current assets - Wildfire Fund asset, and $4.8 billion in Non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. As of December 31, 2022, PG&E Corporation and the Utility had recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 15 below.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 10, “Derivatives” in Note 11, “Fair Value Measurements” in Note 12, and “Contingencies and Commitments” in Notes 15 and 16 below.

Voluntary Separation Program

In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income.

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, 2022 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassifications:
Loss on investments (net of taxes of $0, $0 and $3, respectively)	—		—		(6)		(6)
Unrecognized net actuarial gain (net of taxes of $102, $99 and $0, respectively)	263		(255)		—		8
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively)	(242)		255		—		13
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1, $2 and $0, respectively) (1)	(3)		5		—		2
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively) (1)	1		(29)		—		(28)
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1)	2		24		—		26
Net current period other comprehensive income (loss)	21		—		(6)		15
Ending balance	$	(12)	$	18	$	(6)	$	—

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 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, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively)(1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 below for additional details.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2022 and 2021.

For the years ended December 31, 2022 and 2021, the Utility made total cash payments, including fixed and variable, of $2.3 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements and the Oakland lease. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 16 below.

PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. Property arrangements primarily consist of an office lease agreement for the Lakeside Building. On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease began on April 8, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). On February 6, 2023, the process of subdividing the real estate was completed. If the option is exercised pursuant to the terms of the existing agreement then the Purchase Price would be paid in or around July 2023.

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2022, approximately 488,000 rentable square feet of the leased premises has been made available for use by the Utility. The Utility has recorded approximately $535 million in Operating lease right of use assets, approximately $214 million of leasehold improvements, which includes approximately $137 million that was provided to the Utility as lease incentives, and approximately $672 million in noncurrent Operating lease liabilities in the Consolidated Financial Statements related to the Lease.

In January 2023, approximately 110,000 of additional rentable square feet was made available for use by the Utility.

At December 31, 2022 and 2021, the Utility’s operating leases had a weighted average remaining lease term of 19.6 years and 6.04 years and a weighted average discount rate of 6.5% and 6.1%, respectively.

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:

	Year Ended December 31,
(in millions)	2022		2021
Operating lease fixed cost	$	500	$	578
Operating lease variable cost	1,829		1,782
Total operating lease costs	$	2,329	$	2,360

At December 31, 2022, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2022
2023	$	307
2024	150
2025	146
2026	143
2027	142
Thereafter	2,196
Total lease payments	3,084
Less imputed interest	(1,610)
Total	$	1,474

Recently Adopted Accounting Standards

Debt

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Reference Rate Reform

On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2022		2021
Pension benefits (1)	$	120	$	708	Indefinitely
Environmental compliance costs	1,193		1,089		32 years
Utility retained generation (2)	86		133		4 years
Price risk management	177		216		17 years
Catastrophic event memorandum account (3)	1,085		1,119		1 - 3 years
Wildfire expense memorandum account (4)	439		347		TBD years
Fire hazard prevention memorandum account (5)	79		75		1 - 3 years
Fire risk mitigation memorandum account (6)	65		44		1 - 3 years
Wildfire mitigation plan memorandum account (7)	756		424		1 - 3 years
Deferred income taxes (8)	2,730		1,849		51 years
Insurance premium costs (9)	99		207		2 - 4 years
Wildfire mitigation balancing account (10)	327		273		1 - 3 years
Vegetation management balancing account (11)	2,276		1,411		1 - 3 years
COVID-19 pandemic protection memorandum accounts (12)	26		49		TBD years
Microgrid memorandum account (13)	213		163		1 - 3 years
Financing costs (14)	211		175		Various
SB 901 securitization (15)	5,378		—		30 years
AROs in excess of recoveries (16)	120		—		Various
Other	1,063		925		Various
Total long-term regulatory assets	$	16,443	$	9,207

(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) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 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) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2022 and 2021, $44 million and $49 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.

(6) Includes costs primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. Recovery of WMPMA costs is subject to CPUC review and approval.

(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.

(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2022. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.

(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.

(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date.

(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below.

(16) 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 asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  See Note 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2022 and 2021, the Utility had current regulatory liabilities of $1.12 billion and $698 million, respectively. At December 31, 2022, current regulatory liabilities consisted primarily of unrealized gains associated with the change in fair value of price risk management instruments that meet the definition of a derivative. An increase in natural gas prices has affected both the Utility’s gas and electric price risk management instruments, resulting in a deferral of $604 million. For more information, see Note 11 below. Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2022		2021
Cost of removal obligations (1)	$	7,773	$	7,306
Recoveries in excess of AROs (2)	—		388
Public purpose programs (3)	1,062		946
Employee benefit plans (4)	904		1,229
Transmission tower wireless licenses (5)	430		446
SFGO sale (6)	264		343
SB 901 securitization (7)	5,800		—
Other	1,397		1,341
Total long-term regulatory liabilities	$	17,630	$	11,999

(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.

(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 held 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 12 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.

(4) Represents cumulative differences between incurred costs and amounts collected in rates for post-retirement medical, post-retirement life and long-term disability plans.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.

(7) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement. See Note 6 below.

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 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)	2022		2021
Electric distribution (1)	$	448	$	—
Gas distribution and transmission (2)	72		—
Energy procurement (3)	684		310
Public purpose programs (4)	358		321
Fire hazard prevention memorandum account (5)	—		50
Fire risk mitigation memorandum account (6)	—		14
Wildfire mitigation plan memorandum account (7)	—		67
Wildfire mitigation balancing account (8)	2		91
General rate case memorandum accounts (9)	3		468
Vegetation management balancing account (10)	137		127
Insurance premium costs (11)	602		605
Wildfire expense memorandum account (12)	—		440
Residential uncollectibles balancing accounts (13)	126		127
Catastrophic event memorandum account	144		—
Other	688		379
Total regulatory balancing accounts receivable	$	3,264	$	2,999

	Payable Balance at December 31,
(in millions)	2022		2021
Electric distribution (1)	$	—	$	121
Electric transmission (14)	228		24
Gas distribution and transmission (2)	66		83
Energy procurement (3)	428		211
Public purpose programs (4)	272		259
Nuclear decommissioning adjustment mechanism (15)	8		137
SFGO sale	152		21
Other	504		265
Total regulatory balancing accounts payable	$	1,658	$	1,121

(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(2) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings. 

(3) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. 

(4) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery.

(9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC.

(10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery.

(11) The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets.

(12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022.

(13) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers.

(14) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.

(15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant.

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DEBT

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

DEBT

DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2022:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2027	$	4,400	(1)	$	(1,930)	$	(998)	$	1,472
Utility receivables securitization program (2)	September 2024	1,389		(3)	(1,184)		—		205		(3)
PG&E Corporation revolving credit facility	June 2025	500			—		—		500
Total credit facilities		$	6,289		$	(3,114)	$	(998)	$	2,177

(1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”).

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order.

For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above.

Long-Term Debt Issuances and Redemptions

Utility

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2022		December 31, 2021
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,681	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of unamortized discount and debt issuance costs		(28)		(26)
Unamortized discount/premium and debt issuance costs, net		(66)		(90)
Total PG&E Corporation Long-Term Debt		4,587		4,593
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	—		500
2022	1.75%	—		2,500
2023	1.70% - 4.25%	2,075		3,575
2024	3.25% - 3.75%	1,800		800
2025	3.45% - 4.95%	1,925		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		2,550
2028	3.00% - 4.65%	1,975		1,975
2029	4.20%	400		—
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		—
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		700
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
2052	5.25%	550		—
Less: current portion, net of unamortized discount and debt issuance costs		(2,072)		(2,996)
Unamortized discount, premium and debt issuance costs, net		(195)		(190)
Total Utility First Mortgage Bonds		32,135		31,816
Recovery Bonds (3)		9,292		860
Less: current portion		(168)		(18)
DWR Loan (4)		312		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2024	variable rate (5)	1,184		974
2-Year Term Loan - Stated Maturity: 2024	variable rate (6)	400		—
18-month Term Loan - Stated Maturity: 2023	variable rate (7)	—		1,441
Less: current portion		—		(1,441)
Total Utility Long-Term Debt		43,155		33,632
Total PG&E Corporation Consolidated Long-Term Debt		$	47,742	$	38,225

(1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively.

(2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates.

(4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance.

(5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%.

(6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%.

(7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below:

(in millions, except interest rates)	2023			2024			2025			2026			2027			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2022	7.13		%	7.13		%	7.13		%	—		%	—		%	—		%	7.13		%
Variable rate obligations	$	28		$	28		$	2,625		$	—		$	—		$	—		$	2,681
Utility (1)
Average fixed interest rate	2.91		%	3.40		%	3.82		%	3.10		%	3.22		%	4.12		%	3.84		%
Fixed rate obligations	$	2,075		$	1,800		$	1,925		$	2,551		$	3,000		$	23,051		$	34,402
Variable interest rate as of December 31, 2022	—		%	5.54		%	—		%	—		%	—		%	—		%	5.54		%
Variable rate obligations	$	—		$	1,584		$	—		$	—		$	—		$	—		$	1,584
Recovery Bonds (2)
AB 1054 obligations	$	38		$	46		$	48		$	50		$	51		$	1,592		$	1,825
SB 901 obligations	$	130		$	129		$	135		$	141		$	146		$	6,786		$	7,467
Total consolidated debt	$	2,271		$	3,587		$	4,733		$	2,742		$	3,197		$	33,429		$	49,959

(1) The balance excludes DWR loan, see Note 3 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6.

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable.

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date.

On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date.

Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 12). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

Also pursuant to the CHT decision, upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (See Note 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes.

The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities:

SB 901 securitization regulatory asset (in millions)
Regulatory asset balance at inception	$	5,500
Amortization	(122)
Balance at December 31, 2022	$	5,378

SB 901 securitization regulatory liability (in millions)
Regulatory liability balance at inception	$	(5,540)
Amortization	308
Additions	(568)
Balance at December 31, 2022	$	(5,800)

XML

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2022:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2027	$	4,400	(1)	$	(1,930)	$	(998)	$	1,472
Utility receivables securitization program (2)	September 2024	1,389		(3)	(1,184)		—		205		(3)
PG&E Corporation revolving credit facility	June 2025	500			—		—		500
Total credit facilities		$	6,289		$	(3,114)	$	(998)	$	2,177

(1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”).

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order.

For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above.

Long-Term Debt Issuances and Redemptions

Utility

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2022		December 31, 2021
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,681	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of unamortized discount and debt issuance costs		(28)		(26)
Unamortized discount/premium and debt issuance costs, net		(66)		(90)
Total PG&E Corporation Long-Term Debt		4,587		4,593
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	—		500
2022	1.75%	—		2,500
2023	1.70% - 4.25%	2,075		3,575
2024	3.25% - 3.75%	1,800		800
2025	3.45% - 4.95%	1,925		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		2,550
2028	3.00% - 4.65%	1,975		1,975
2029	4.20%	400		—
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		—
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		700
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
2052	5.25%	550		—
Less: current portion, net of unamortized discount and debt issuance costs		(2,072)		(2,996)
Unamortized discount, premium and debt issuance costs, net		(195)		(190)
Total Utility First Mortgage Bonds		32,135		31,816
Recovery Bonds (3)		9,292		860
Less: current portion		(168)		(18)
DWR Loan (4)		312		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2024	variable rate (5)	1,184		974
2-Year Term Loan - Stated Maturity: 2024	variable rate (6)	400		—
18-month Term Loan - Stated Maturity: 2023	variable rate (7)	—		1,441
Less: current portion		—		(1,441)
Total Utility Long-Term Debt		43,155		33,632
Total PG&E Corporation Consolidated Long-Term Debt		$	47,742	$	38,225

(1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively.

(2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates.

(4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance.

(5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%.

(6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%.

(7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below:

(in millions, except interest rates)	2023			2024			2025			2026			2027			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2022	7.13		%	7.13		%	7.13		%	—		%	—		%	—		%	7.13		%
Variable rate obligations	$	28		$	28		$	2,625		$	—		$	—		$	—		$	2,681
Utility (1)
Average fixed interest rate	2.91		%	3.40		%	3.82		%	3.10		%	3.22		%	4.12		%	3.84		%
Fixed rate obligations	$	2,075		$	1,800		$	1,925		$	2,551		$	3,000		$	23,051		$	34,402
Variable interest rate as of December 31, 2022	—		%	5.54		%	—		%	—		%	—		%	—		%	5.54		%
Variable rate obligations	$	—		$	1,584		$	—		$	—		$	—		$	—		$	1,584
Recovery Bonds (2)
AB 1054 obligations	$	38		$	46		$	48		$	50		$	51		$	1,592		$	1,825
SB 901 obligations	$	130		$	129		$	135		$	141		$	146		$	6,786		$	7,467
Total consolidated debt	$	2,271		$	3,587		$	4,733		$	2,742		$	3,197		$	33,429		$	49,959

(1) The balance excludes DWR loan, see Note 3 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6.

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable.

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date.

On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date.

Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 12). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

Also pursuant to the CHT decision, upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (See Note 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes.

The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities:

SB 901 securitization regulatory asset (in millions)
Regulatory asset balance at inception	$	5,500
Amortization	(122)
Balance at December 31, 2022	$	5,378

SB 901 securitization regulatory liability (in millions)
Regulatory liability balance at inception	$	(5,540)
Amortization	308
Additions	(568)
Balance at December 31, 2022	$	(5,800)

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COMMON STOCK AND SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2022

Common Stock And Share-Based Compensation [Abstract]

COMMON STOCK AND SHARE-BASED COMPENSATION

COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,987,784,948 shares of common stock outstanding at December 31, 2022, which excludes 247,743,590 shares of common stock owned by ShareCo, and 230,000,000 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2022.

Equity Offerings

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts.

At the Market Equity Distribution Program

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.

The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.

On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of the outstanding shares. At various dates throughout 2022, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

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.  Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.  

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

Long-Term Incentive Plans

The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, 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 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 53,350,101 shares were available for future awards at December 31, 2022.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2022:

(in millions)	2022		2021		2020
Stock Options	$	—	$	—	$	3
Restricted stock units	60		35		15
Performance shares	55		21		17
Total compensation expense (pre-tax)	$	115	$	56	$	35
Total compensation expense (after-tax)	$	83	$	40	$	25

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2022, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2022 or 2021.  

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2022.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,195,834	$	7.42		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(43,702)	10.23			—
Outstanding at December 31	2,152,132	7.36		2.41	—
Vested or expected to vest at December 31	2,152,132	7.36		2.41	—
Exercisable at December 31	2,152,132	$	7.36	2.41	$	—

(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units 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 ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2022, 2021, and 2020 was $11.40, $11.01, and $9.25, respectively.  The total fair value of restricted stock units that vested during 2022, 2021, and 2020 was $46 million, $19 million, and $31 million, respectively.  The tax detriment from restricted stock units that vested in 2022 was $4 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2022, $74 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48 years.

The following table summarizes restricted stock unit activity for 2022:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	10,090,375	$	11.00
Granted	5,850,945	11.40
Vested	(4,175,008)	10.96
Forfeited	(788,192)	11.18
Nonvested at December 31	10,978,120	$	11.21

Performance Shares

Performance shares generally vest three years after the grant date.  Following 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 (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-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 during 2022, 2021, and 2020 was $13.44, $11.83, and $9.62 respectively.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2022, $43 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 0.94 years.

The following table summarizes activity for performance shares in 2022:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	8,567,009	$	9.64
Granted	3,105,604	13.44
Vested	—	—
Forfeited	(650,559)	10.15
Nonvested at December 31	11,022,054	$	10.68

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PREFERRED STOCK

12 Months Ended

Dec. 31, 2022

Preferred Stock [Abstract]

PREFERRED STOCK

PREFERRED STOCK

PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2022 and 2021, 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, respectively.  The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

On December 31, 2022, 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, 2022, 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.  On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the dividends paid in arrears, the Utility paid approximately $11 million of dividends on redeemable preferred stock during the year ended December 31, 2022. On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023.

The Utility paid no dividends on preferred stock in 2021 or 2020.

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2022, 2021, and 2020.

	Year Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Income (loss) available for common shareholders	$	1,800	$	(102)	$	(1,318)
Weighted average common shares outstanding, basic	1,987		1,985		1,257
Add incremental shares from assumed conversions:
Employee share-based compensation	8		—		—
Equity Units	137		—		—
Weighted average common shares outstanding, diluted	2,132		1,985		1,257
Total earnings (loss) per common share, diluted	$	0.84	$	(0.05)	$	(1.05)

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, 2022

Income Tax Disclosure [Abstract]

INCOME TAXES

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 DTAs and liabilities.  DTAs 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 technical 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)	2022		2021		2020		2022		2021		2020
Current:
Federal	$	(1)	$	—	$	(26)	$	(1)	$	—	$	(26)
State	—		1		(34)		—		—		(34)
Deferred:
Federal	(943)		543		258		(852)		588		290
State	(389)		296		171		(348)		316		185
Tax credits	(5)		(4)		(7)		(5)		(4)		(7)
Income tax provision (benefit)	$	(1,338)	$	836	$	362	$	(1,206)	$	900	$	408

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2022		2021		2022		2021
Deferred income tax assets:
Tax carryforwards	$	7,156	$	5,628	$	6,868	$	5,425
Compensation	157		185		80		108
Greenhouse gas allowance	239		157		239		157
Wildfire-related claims (1)	1,489		1,723		1,489		1,723
Operating lease liability	368		346		368		346
Transmission tower wireless licenses	254		266		254		266
Other (2)	197		121		177		136
Total deferred income tax assets	$	9,860	$	8,426	$	9,475	$	8,161
Deferred income tax liabilities:
Property related basis differences	9,374		8,847		9,363		8,835
Regulatory balancing accounts	1,376		1,193		1,376		1,193
Debt financing costs	465		501		465		501
Operating lease right of use asset	368		346		368		346
Income tax regulatory asset (3)	764		517		764		517
Other (4)	245		199		230		178
Total deferred income tax liabilities	$	12,592	$	11,603	$	12,566	$	11,570
Total net deferred income tax liabilities	$	2,732	$	3,177	$	3,091	$	3,409

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service area over the past several years.

(2) Amounts include benefits, state taxes, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

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,
	2022		2021		2020		2022		2021		2020
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(75.8)		31.3		(15.3)		(26.9)		24.1		19.1
Effect of regulatory treatment of fixed asset differences (2)	(123.8)		(71.5)		39.0		(49.2)		(51.6)		(44.9)
Tax credits	(3.2)		(1.7)		1.5		(1.3)		(1.2)		(1.7)
Fire Victim Trust (3)	(160.9)		127.3		(44.9)		(64.0)		91.9		51.7
Bankruptcy and emergence	—		—		(37.6)		—		—		2.4
Other, net (4)	12.9		5.3		(2.1)		2.2		2.6		2.2
Effective tax rate	(329.8)	%	111.7	%	(38.4)	%	(118.2)	%	86.8	%	49.8	%

(1) Includes the effect of state flow-through ratemaking treatment.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  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.  In 2022, 2021, and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) The Utility includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2022		2021		2020		2022		2021		2020
Balance at beginning of year	$	498	$	437	$	420	$	498	$	437	$	420
Reductions for tax position taken during a prior year	(1)		(23)		(43)		(1)		(23)		(43)
Additions for tax position taken during the current year	73		85		60		73		85		60
Settlements	—		(1)		—		—		(1)		—
Balance at end of year	$	570	$	498	$	437	$	570	$	498	$	437

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2022 for PG&E Corporation and the Utility was $31 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress.

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, 2022, 2021, and 2020, these amounts were immaterial.

Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. The Internal Revenue Service is auditing tax years 2015 through 2018.

PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California. The State of California is auditing tax years 2015 through 2019.

Carryforwards

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

(in millions)	December 31, 2022		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,447	2031 - 2036
Net operating loss carryforward - Post-2017	23,170		N/A
Tax credit carryforward	152		2029 - 2041
State:
Net operating loss carryforward	$	25,169	2039 - 2041
Tax credit carryforward	126		Various

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.

Other Tax Matters

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. Half of the payment was paid in 2021, and the other half of the payment was paid in 2022.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). Due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. From inception through December 31, 2022, the Fire Victim Trust exchanged Plan Shares in the aggregate amount of 230,000,000 for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. In the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. On January 9, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares and thereafter the Fire Victim Trust reported that it sold the applicable New Shares. An aggregate tax benefit of $256 million will be recorded in January 2023. For more information, see Note 7 above.

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DERIVATIVES

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

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 rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and 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 through 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. 

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume at
Underlying Product	Instruments	December 31, 2022	December 31, 2021
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	171,212,813	173,361,635
	Options	27,785,000	14,420,000
Electricity (MWh)	Forwards, Futures and Swaps	10,814,728	10,283,639
	Options	215,600	288,000
	Congestion Revenue Rights (3)	205,743,505	239,857,610

(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

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

As of December 31, 2021, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.

Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2022, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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:

•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	658	$	—	$	—	$	—	$	658
Fixed-income securities	—		49		—		—		49
Nuclear decommissioning trusts
Short-term investments	117		—		—		—		117
Global equity securities	1,845		—		—		—		1,845
Fixed-income securities	1,094		791		—		—		1,885
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,056		791		—		—		3,872
Customer credit trust
Short-term investments	19		—		—		—		19
Global equity securities	218		—		—		—		218
Fixed-income securities	216		292		—		—		508
Total customer credit trust	453		292		—		—		745
Price risk management instruments (Note 11)
Electricity	—		94		432		40		566
Gas	—		604		—		327		931
Total price risk management instruments	—		698		432		367		1,497
Rabbi trusts
Short-term investments	25		—		—		—		25
Global equity securities	5		—		—		—		5
Fixed-income securities	—		69		—		—		69
Life insurance contracts	—		64		—		—		64
Total rabbi trusts	30		133		—		—		163
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	10		—		—		—		143
TOTAL ASSETS	$	4,207	$	1,963	$	432	$	367	$	7,127
Liabilities:
Price risk management instruments (Note 11)
Electricity	$	—	$	10	$	233	$	(20)	$	223
Gas	—		172		—		(166)		6
TOTAL LIABILITIES	$	—	$	182	$	233	$	(186)	$	229

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

(2) Represents amount before deducting $575 million primarily related to deferred taxes on appreciation of investment value. 

	Fair Value Measurements
	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 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. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2022 and 2021.

Trust Assets

Assets Measured at Fair Value

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, customer credit 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 classified as 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 fixed-income 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 Using Practical Expedient

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, credit securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, 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 futures 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 futures, 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.  The Utility 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 Uncertainty Analysis

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 rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments.  See Note 11 above.

	Fair Value at
(in millions)	At December 31, 2022				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	305	$	138	Market approach	CRR auction prices	$ (145.09) - 2,724.93 / 0.89
Power purchase agreements	$	127	$	95	Discounted cash flow	Forward prices	$ (6.39) - 286.75 / 78.14

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2022 and 2021, respectively:

	Price Risk Management Instruments
(in millions)	2022		2021
Liability balance as of January 1	$	(34)	$	(72)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	233		38
Asset (Liability) balance as of December 31	$	199	$	(34)

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

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, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of December 31, 2022 and December 31, 2021, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At December 31, 2022				At December 31, 2021
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,355	$	4,490	$	4,619	$	4,796
Utility	32,847		27,666		31,816		35,803

Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Nuclear decommissioning trusts
Short-term investments	$	117	$	—	$	—	$	117
Global equity securities	413		1,468		(11)		1,870
Fixed-income securities	1,991		10		(116)		1,885
Total (1)	$	2,521	$	1,478	$	(127)	$	3,872
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581

(1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, 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, 2022
Less than 1 year	$	42
1–5 years	624
5–10 years	400
More than 10 years	819
Total maturities of fixed-income securities	$	1,885

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

(in millions)	2022		2021		2020
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	3,316	$	1,678	$	1,518
Gross realized gains on securities	2		286		159
Gross realized losses on securities	(3)		(19)		(41)

Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Customer credit trust
Short-term investments	$	19	$	—	$	—	$	19
Global equity securities	219		13		(14)		218
Fixed-income securities	516		—		(8)		508
Total	$	754	$	13	$	(22)	$	745

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

	As of
(in millions)	December 31, 2022
Less than 1 year	$	79
1–5 years	123
5–10 years	120
More than 10 years	186
Total maturities of fixed-income securities	$	508

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

(in millions)	2022
Proceeds from sales and maturities of customer credit trust investments	$	250
Gross realized gains on securities	10
Gross realized losses on securities (1)	(41)

(1) Includes $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2022.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2022

Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]

EMPLOYEE BENEFIT PLANS

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”).  Certain trusts underlying these plans are qualified trusts under the IRC.  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.  On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates.

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 2022 and 2021:

Pension Plan

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	21,895	$	20,759
Actual return on plan assets	(4,916)		1,693
Company contributions	339		335
Benefits and expenses paid	(949)		(892)
Fair value of plan assets at end of year	$	16,369	$	21,895
Change in benefit obligation:
Benefit obligation at beginning of year	$	22,759	$	23,172
Service cost for benefits earned	575		587
Interest cost	692		645
Actuarial gain (1)	(6,471)		(752)
Plan amendments	—		—
Benefits and expenses paid	(947)		(893)
Benefit obligation at end of year (2)	$	16,608	$	22,759
Funded Status:
Current liability	$	(8)	$	(9)
Noncurrent liability	(231)		(856)
Net liability at end of year	$	(239)	$	(865)

(1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	3,102	$	2,995
Actual return on plan assets	(693)		193
Company contributions	26		10
Plan participant contribution	81		80
Benefits and expenses paid	(180)		(176)
Fair value of plan assets at end of year	$	2,336	$	3,102
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766	$	1,876
Service cost for benefits earned	62		63
Interest cost	53		51
Actuarial gain (1)	(486)		(152)
Benefits and expenses paid	(162)		(156)
Federal subsidy on benefits paid	3		4
Plan participant contributions	81		80
VSP related termination benefits (3)	22		—
Benefit obligation at end of year	$	1,339	$	1,766
Funded Status: (2)
Noncurrent asset	$	997	$	1,340
Noncurrent liability	—		(4)
Net asset at end of year	$	997	$	1,336

(1) The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes

(2) At December 31, 2022 and 2021, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively.

(3) Represents VSP-related credits to employee retirement health savings accounts. See Note 3 above.

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

Components of Net Periodic Benefit Cost

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.

Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	575	$	587	$	530
Interest cost	692		645		713
Expected return on plan assets	(1,189)		(1,046)		(1,044)
Amortization of prior service cost	(4)		(6)		(6)
Amortization of net actuarial loss	2		6		3
Net periodic benefit cost	76		186		196
Less: transfer to regulatory account (2)	254		147		136
Total expense recognized	$	330	$	333	$	332

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	62	$	63	$	61
Interest cost	53		51		63
Expected return on plan assets	(130)		(137)		(138)
Amortization of prior service cost	7		14		14
Amortization of net actuarial loss	(40)		(33)		(21)
Special termination benefits	22		—		—
Net periodic benefit cost	$	(26)	$	(42)	$	(21)

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.

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).

Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2022		2021		2020		2022	2021	2020
Discount rate	5.54	%	3.03	%	2.77	%	5.50 - 5.54%	2.97 - 3.04%	2.67 - 2.80%
Rate of future compensation increases	3.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.10	%	5.50	%	5.10	%	3.70 - 7.30%	3.30 - 6.40%	3.10 - 6.10%
Interest crediting rate for cash balance plan	4.19	%	1.95	%	1.95	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2022 was 6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 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 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 projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.1% compares to a ten-year actual return of 5.8%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 848 Aa-grade non-callable bonds at December 31, 2022.  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 global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios. 

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 allocation between fixed income and equity 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
	2023		2022		2021		2023		2022		2021
Global equity securities	26	%	30	%	30	%	28	%	26	%	36	%
Absolute return	1	%	2	%	2	%	1	%	1	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	5	%
Fixed-income securities	65	%	60	%	60	%	68	%	70	%	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, 2022 and 2021.

	Fair Value Measurements
	At December 31,
	2022								2021
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	461	$	126	$	—	$	587	$	552	$	255	$	—	$	807
Global equity securities	1,430		—		—		1,430		2,074		424		—		2,498
Absolute Return	—		—		—		—		—		1		—		1
Real assets	426		—		—		426		632		—		—		632
Fixed-income securities	1,946		6,086		8		8,040		2,729		7,388		27		10,144
Assets measured at NAV	—		—		—		5,886		—		—		—		7,972
Total	$	4,263	$	6,212	$	8	$	16,369	$	5,987	$	8,068	$	27	$	22,054
PBOP Plans:
Short-term investments	$	26	$	—	$	—	$	26	$	31	$	—	$	—	$	31
Global equity securities	83		—		—		83		105		—		—		105
Real assets	29		—		—		29		34		—		—		34
Fixed-income securities	406		702		1		1,109		776		875		1		1,652
Assets measured at NAV	—		—		—		1,100		—		—		—		1,296
Total	$	544	$	702	$	1	$	2,347	$	946	$	875	$	1	$	3,118
Total plan assets at fair value							$	18,716							$	25,172

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $11 million and $175 million at December 31, 2022 and 2021, 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 NAV 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 Securities

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 Securities

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.

Assets Measured at NAV Using Practical Expedient

Investments in the trusts 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, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2022 or 2021.

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, 2022 and 2021:

(in millions)
For the year ended December 31, 2022	Fixed-Income
Balance at beginning of year	$	27
Actual return on plan assets:
Relating to assets still held at the reporting date	1
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	(26)
Balance at end of year	$	8
(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27

There were no material transfers out of Level 3 in 2022 or 2021.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $339 million to the pension benefit plans and $26 million to the other benefit plans in 2022.  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 2022.  The Utility’s pension benefits met all the funding requirements under the Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2023. PG&E Corporation and the Utility did not request to make contributions to the other postretirement benefit plans in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2022, 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:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2023	907	97	(4)
2024	996	98	(4)
2025	1028	100	(4)
2026	1057	94	(4)
2027	1,082	94	(4)
Thereafter in the succeeding five years	5,702	475	(4)

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 IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provides 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 $144 million, $133 million, and $119 million in 2022, 2021, and 2020, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

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, 2022

Related Party Transactions [Abstract]

RELATED PARTY AGREEMENTS AND TRANSACTIONS

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)	2022		2021		2020
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	104	$	82	$	108
Utility employee benefit due to PG&E Corporation	85		39		34

At December 31, 2022 and 2021, the Utility had receivables of $33 million and $173 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $46 million and $19 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

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WILDFIRE-RELATED CONTINGENCIES

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation.

On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022.

On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire.

Additionally, on July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	769
Accrued Losses	225
Payments	(344)
Balance at December 31, 2022	$	650

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

Various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for August 14, 2023.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	211
Accrued Losses	25
Payments	(204)
Balance at December 31, 2022	$	32

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2022, the Utility recorded an insurance receivable for $370 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $30 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation.

On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	1,150
Accrued Losses	25
Payments	(44)
Balance at December 31, 2022	$	1,131

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of December 31, 2022, the Utility recorded an insurance receivable of $530 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $370 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2022, the Utility recorded a Wildfire Fund receivable of $175 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $115 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $388 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. The WEMA regulatory asset increased by $41 million during the year ended December 31, 2022.

2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 13 structures damaged, and 78 structures destroyed and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 236 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further such complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency and a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million during the quarter ended September 30, 2022 (before available recoveries). The aggregate liability remained unchanged as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. The Utility’s accrued estimated losses also do not include any assumptions regarding offsetting recoveries from third-parties (outside of the Utility’s insurers).

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $940 million, with a deductible of $60 million. As of December 31, 2022, the Utility recorded an insurance receivable of $45 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of December 31, 2022, the Utility also recorded a $10 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $50 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2022 are:

Potential Recovery Source (in millions)	2022 Mosquito fire		2021 Dixie fire
Insurance	$	45	$	530
FERC TO rates	10		115
WEMA	50		388
Wildfire Fund	—		175
Probable recoveries at December 31, 2022	$	105	$	1,208

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In April 2022, the Utility purchased approximately $725 million in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of December 31, 2022, PG&E Corporation and the Utility had prepaid insurance of $424 million, reflected in Other current assets on the Consolidated Balance Sheets.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2022, PG&E Corporation and the Utility recorded $430 million, $370 million, $530 million, and $45 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2021	$	—	$	563	$	270	$	414	$	1,247
Accrued insurance recoveries (1)	45		(33)		33		—		45
Reimbursements	—		—		(185)		(313)		(498)
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794

(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

During the year ended December 31, 2022, PG&E Corporation and the Utility resolved property related claims in the amount of $418 million, net of self-insured retention, of which approximately $13 million is reflected in Accounts receivable, other on the Consolidated Financial Statements (excluded from the table above).

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2022, the Utility recorded reductions of $115 million and $10 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of December 31, 2022, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $388 million and $50 million, respectively, as regulatory assets in the WEMA. Cost recovery for incremental insurance premiums is addressed through balancing account mechanisms.

Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of December 31, 2022 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.0 billion based on its 2022 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

As of December 31, 2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview

As further described under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. These securities claims are collectively referred to in this section as the “Wildfire-Related Securities Claims.”

Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the terms of the FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with certain carriers of the D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the Wildfire-Related Securities Claims. As of December 31, 2022 and each as further described below:

•For the Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the consolidated securities action, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.

•For the Insurance Coverage Claims, PG&E Corporation entered into agreements with certain of its D&O Insurance carriers to settle the majority of the Insurance Coverage Claims and has received the full settlement amount of $272 million.

•For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O insurance policy proceeds. PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

As a result, PG&E Corporation believes it is probable that it will incur a net loss of $145 million in connection with these matters. As of December 31, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Consolidated Statements of Income.

In the event that one or more of the settlements in these matters does not become effective, some or all parties are expected to continue to litigate, and at least some of the amounts of PG&E Corporation’s expected liabilities will remain uncertain.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain then-current and former members of the boards of directors and certain then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). On April 13, 2018, the plaintiffs filed a consolidated complaint. On January 28, 2019, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims, if any, directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation or the Utility for amounts owed pursuant to their indemnification obligations in connection with such causes of action. On March 8, 2021, the court granted a stipulation by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.

On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O Insurance policy proceeds, and in return, the Fire Victim Trust released, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement was paid solely from the insurance proceeds from the “Side B” D&O Insurance coverage. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action was dismissed with prejudice on December 29, 2022.

On January 25, 2019, a separate purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The plaintiff filed a request to dismiss this action, and on October 12, 2022, the court dismissed the action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA’s opening brief for the appeal is due March 6, 2023, and the answering brief is due April 5, 2023.

Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. In the second quarter of 2022, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such agreement.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. PERA’s appeal to the Ninth Circuit Court of Appeals remains pending.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with certain carriers regarding, among other things, the applicability of one year of D&O Insurance policies to those matters (the “Insurance Coverage Claims”).

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled the majority of the Insurance Coverage Claims with certain of their D&O Insurance carriers. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to May 19, 2023.

OTHER CONTINGENCIES AND COMMITMENTSPG&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, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation and the Utility 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’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

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 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. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $258 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

2022 Cost of Capital Application

The Utility’s annual cost of capital adjustment mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure.

In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes beginning on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application. As of December 31, 2022, the Utility had not recorded a reserve for refunds related to these memorandum accounts.

On November 3, 2022, the CPUC issued a final decision finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. The final decision retains the cost of capital previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility filed a response to the application for rehearing.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters totaled $69 million and $77 million as of December 31, 2022 and December 31, 2021, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022.

The Utility is unable to determine the timing and outcome of this proceeding.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded charges during the fourth quarters of 2021 and 2022, each for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities 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. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. 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 comprised of the following:

	Balance at
(in millions)	December 31, 2022		December 31, 2021
Topock natural gas compressor station	$	284	$	299
Hinkley natural gas compressor station	110		123
Former MGP sites owned by the Utility or third parties (1)	750		667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		104
Fossil fuel-fired generation facilities and sites (3)	26		70
Total environmental remediation liability	$	1,282	$	1,263

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.

(2) Primarily driven by geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP 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 Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program 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 the environmental requirements on an ongoing basis 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 as of December 31, 2022, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  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. As of December 31, 2022, the Utility expected to recover $1.05 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $240 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater 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 California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility 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 sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2023. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $126 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $511 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $51 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more terrorist acts occurring within a 12-month period at member sites. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more cyber events occurring within a 12-month period at member sites. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, 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. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. The coverage procured through EMANI also includes protection for acts of terrorism.

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, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

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 approximately $13.7 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.7 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

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 $450 million per incident. In addition, the Utility has approximately $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 for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

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, 2022:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2023	$	2,081	$	482	$	60	$	1,746	$	47	$	4,416
2024	2,052		378		61		195		11		2,697
2025	2,040		715		61		140		—		2,956
2026	1,980		663		21		129		—		2,793
2027	1,919		579		7		53		—		2,558
Thereafter	17,807		1,565		13		—		—		19,385
Total purchase commitments	$	27,879	$	4,382	$	223	$	2,263	$	58	$	34,805

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.  These renewable energy contracts expire at various dates between 2023 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 RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2023 and 2041.

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. As of December 31, 2022, QF contracts in operation expire at various dates between 2023 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.8 billion in 2022, $3.0 billion in 2021, and $2.9 billion in 2020.

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 United States 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 2023 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California 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, were $2.4 billion in 2022, $1.2 billion in 2021, and $0.8 billion in 2020.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2023 and 2024 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 were $44 million in 2022, $79 million in 2021, and $111 million in 2020.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2023 and 2057.  At December 31, 2022, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2023	$	88
2024	85
2025	83
2026	81
2027	80
Thereafter	3,518
Total minimum lease payments	$	3,935

Payments for other commitments were $63 million in 2022, $50 million in 2021, and $45 million in 2020.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

In addition to the commitments in the table above, pursuant to SB 901, a shareholder contribution to the customer credit trust of $1.0 billion is to be made in 2024.

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OTHER CONTINGENCIES AND COMMITMENTS

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

OTHER CONTINGENCIES AND COMMITMENTS

WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation.

On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022.

On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire.

Additionally, on July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	769
Accrued Losses	225
Payments	(344)
Balance at December 31, 2022	$	650

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

Various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for August 14, 2023.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	211
Accrued Losses	25
Payments	(204)
Balance at December 31, 2022	$	32

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2022, the Utility recorded an insurance receivable for $370 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $30 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation.

On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	1,150
Accrued Losses	25
Payments	(44)
Balance at December 31, 2022	$	1,131

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of December 31, 2022, the Utility recorded an insurance receivable of $530 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $370 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2022, the Utility recorded a Wildfire Fund receivable of $175 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $115 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $388 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. The WEMA regulatory asset increased by $41 million during the year ended December 31, 2022.

2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 13 structures damaged, and 78 structures destroyed and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 236 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further such complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency and a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million during the quarter ended September 30, 2022 (before available recoveries). The aggregate liability remained unchanged as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. The Utility’s accrued estimated losses also do not include any assumptions regarding offsetting recoveries from third-parties (outside of the Utility’s insurers).

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $940 million, with a deductible of $60 million. As of December 31, 2022, the Utility recorded an insurance receivable of $45 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of December 31, 2022, the Utility also recorded a $10 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $50 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2022 are:

Potential Recovery Source (in millions)	2022 Mosquito fire		2021 Dixie fire
Insurance	$	45	$	530
FERC TO rates	10		115
WEMA	50		388
Wildfire Fund	—		175
Probable recoveries at December 31, 2022	$	105	$	1,208

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In April 2022, the Utility purchased approximately $725 million in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of December 31, 2022, PG&E Corporation and the Utility had prepaid insurance of $424 million, reflected in Other current assets on the Consolidated Balance Sheets.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2022, PG&E Corporation and the Utility recorded $430 million, $370 million, $530 million, and $45 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2021	$	—	$	563	$	270	$	414	$	1,247
Accrued insurance recoveries (1)	45		(33)		33		—		45
Reimbursements	—		—		(185)		(313)		(498)
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794

(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

During the year ended December 31, 2022, PG&E Corporation and the Utility resolved property related claims in the amount of $418 million, net of self-insured retention, of which approximately $13 million is reflected in Accounts receivable, other on the Consolidated Financial Statements (excluded from the table above).

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2022, the Utility recorded reductions of $115 million and $10 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of December 31, 2022, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $388 million and $50 million, respectively, as regulatory assets in the WEMA. Cost recovery for incremental insurance premiums is addressed through balancing account mechanisms.

Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of December 31, 2022 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.0 billion based on its 2022 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

As of December 31, 2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview

As further described under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. These securities claims are collectively referred to in this section as the “Wildfire-Related Securities Claims.”

Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the terms of the FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with certain carriers of the D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the Wildfire-Related Securities Claims. As of December 31, 2022 and each as further described below:

•For the Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the consolidated securities action, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.

•For the Insurance Coverage Claims, PG&E Corporation entered into agreements with certain of its D&O Insurance carriers to settle the majority of the Insurance Coverage Claims and has received the full settlement amount of $272 million.

•For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O insurance policy proceeds. PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

As a result, PG&E Corporation believes it is probable that it will incur a net loss of $145 million in connection with these matters. As of December 31, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Consolidated Statements of Income.

In the event that one or more of the settlements in these matters does not become effective, some or all parties are expected to continue to litigate, and at least some of the amounts of PG&E Corporation’s expected liabilities will remain uncertain.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain then-current and former members of the boards of directors and certain then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). On April 13, 2018, the plaintiffs filed a consolidated complaint. On January 28, 2019, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims, if any, directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation or the Utility for amounts owed pursuant to their indemnification obligations in connection with such causes of action. On March 8, 2021, the court granted a stipulation by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.

On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O Insurance policy proceeds, and in return, the Fire Victim Trust released, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement was paid solely from the insurance proceeds from the “Side B” D&O Insurance coverage. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action was dismissed with prejudice on December 29, 2022.

On January 25, 2019, a separate purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The plaintiff filed a request to dismiss this action, and on October 12, 2022, the court dismissed the action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA’s opening brief for the appeal is due March 6, 2023, and the answering brief is due April 5, 2023.

Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. In the second quarter of 2022, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such agreement.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. PERA’s appeal to the Ninth Circuit Court of Appeals remains pending.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with certain carriers regarding, among other things, the applicability of one year of D&O Insurance policies to those matters (the “Insurance Coverage Claims”).

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled the majority of the Insurance Coverage Claims with certain of their D&O Insurance carriers. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to May 19, 2023.

OTHER CONTINGENCIES AND COMMITMENTSPG&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, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation and the Utility 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’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

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 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. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $258 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

2022 Cost of Capital Application

The Utility’s annual cost of capital adjustment mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure.

In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes beginning on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application. As of December 31, 2022, the Utility had not recorded a reserve for refunds related to these memorandum accounts.

On November 3, 2022, the CPUC issued a final decision finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. The final decision retains the cost of capital previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility filed a response to the application for rehearing.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters totaled $69 million and $77 million as of December 31, 2022 and December 31, 2021, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022.

The Utility is unable to determine the timing and outcome of this proceeding.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded charges during the fourth quarters of 2021 and 2022, each for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities 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. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. 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 comprised of the following:

	Balance at
(in millions)	December 31, 2022		December 31, 2021
Topock natural gas compressor station	$	284	$	299
Hinkley natural gas compressor station	110		123
Former MGP sites owned by the Utility or third parties (1)	750		667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		104
Fossil fuel-fired generation facilities and sites (3)	26		70
Total environmental remediation liability	$	1,282	$	1,263

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.

(2) Primarily driven by geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP 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 Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program 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 the environmental requirements on an ongoing basis 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 as of December 31, 2022, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  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. As of December 31, 2022, the Utility expected to recover $1.05 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $240 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater 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 California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility 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 sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2023. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $126 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $511 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $51 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more terrorist acts occurring within a 12-month period at member sites. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more cyber events occurring within a 12-month period at member sites. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, 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. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. The coverage procured through EMANI also includes protection for acts of terrorism.

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, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

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 approximately $13.7 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.7 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

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 $450 million per incident. In addition, the Utility has approximately $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 for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

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, 2022:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2023	$	2,081	$	482	$	60	$	1,746	$	47	$	4,416
2024	2,052		378		61		195		11		2,697
2025	2,040		715		61		140		—		2,956
2026	1,980		663		21		129		—		2,793
2027	1,919		579		7		53		—		2,558
Thereafter	17,807		1,565		13		—		—		19,385
Total purchase commitments	$	27,879	$	4,382	$	223	$	2,263	$	58	$	34,805

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.  These renewable energy contracts expire at various dates between 2023 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 RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2023 and 2041.

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. As of December 31, 2022, QF contracts in operation expire at various dates between 2023 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.8 billion in 2022, $3.0 billion in 2021, and $2.9 billion in 2020.

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 United States 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 2023 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California 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, were $2.4 billion in 2022, $1.2 billion in 2021, and $0.8 billion in 2020.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2023 and 2024 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 were $44 million in 2022, $79 million in 2021, and $111 million in 2020.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2023 and 2057.  At December 31, 2022, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2023	$	88
2024	85
2025	83
2026	81
2027	80
Thereafter	3,518
Total minimum lease payments	$	3,935

Payments for other commitments were $63 million in 2022, $50 million in 2021, and $45 million in 2020.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

In addition to the commitments in the table above, pursuant to SB 901, a shareholder contribution to the customer credit trust of $1.0 billion is to be made in 2024.

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

12 Months Ended

Dec. 31, 2022

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Administrative service revenue	$	109	$	118	$	127
Operating expenses	(193)		(124)		(103)
Interest income	3		—		—
Interest expense	(261)		(230)		(149)
Other income (expense)	(201)		(54)		13
Reorganization items, net	—		1		(1,649)
Equity in earnings of subsidiaries	2,154		137		411
Income (loss) before income taxes	1,611		(152)		(1,350)
Income tax benefit	(132)		(64)		(46)
Net Income (loss)	$	1,743	$	(88)	$	(1,304)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	$	21	$	7	$	(17)
Total other comprehensive income (loss)	21		7		(17)
Comprehensive Income (Loss)	$	1,764	$	(81)	$	(1,321)
Weighted Average Common Shares Outstanding, Basic (1)	2,235		2,463		1,257
Weighted Average Common Shares Outstanding, Diluted (1)	2,380		2,463		1,257
Net earnings (loss) per common share, basic	$	0.78	$	(0.05)	$	(1.05)
Net earnings (loss) per common share, diluted	$	0.73	$	(0.05)	$	(1.05)

(1) Includes 247,743,590 and 477,743,590 shares of common stock issued to ShareCo as of December 31, 2022 and 2021, respectively.

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED BALANCE SHEETS

	Balance at December 31,
(in millions)	2022		2021
ASSETS
Current Assets
Cash and cash equivalents	$	125	$	126
Advances to affiliates	46		21
Income taxes receivable	10		10
Other current assets	12		12
Total current assets	193		169
Noncurrent Assets
Equipment	—		2
Accumulated depreciation	—		(2)
Net equipment	—		—
Investments in subsidiaries	33,021		30,232
Other investments	160		181
Deferred income taxes	423		297
Total noncurrent assets	33,604		30,710
Total Assets	$	33,797	$	30,879
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current	27		27
Accounts payable – other	88		200
Other current liabilities	369		69
Total current liabilities	484		296
Noncurrent Liabilities
Long-term debt	4,588		4,592
Other noncurrent liabilities	134		168
Total noncurrent liabilities	4,722		4,760
Common Shareholders’ Equity
Common stock	36,132		35,129
Reinvested earnings	(7,542)		(9,286)
Accumulated other comprehensive income (loss)	1		(20)
Total common shareholders’ equity	28,591		25,823
Total Liabilities and Shareholders’ Equity	$	33,797	$	30,879

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2022		2021		2020
Cash Flows from Operating Activities:
Net income (loss)	$	1,743	$	(88)	$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	95		51		28
Equity in earnings of subsidiaries	(2,160)		(139)		(412)
Deferred income taxes and tax credits, net	(126)		(60)		(50)
Reorganization items, net (Note 2)	—		(32)		1,548
Current income taxes receivable/payable	—		2		—
Liabilities subject to compromise	—		—		12
Other	339		81		97
Net cash used in operating activities	(109)		(185)		(81)
Cash Flows From Investing Activities:
Investment in subsidiaries	(994)		—		(12,986)
Dividends received from subsidiaries (1)	1,275		—		—
Net cash provided by (used in) investing activities	281		—		(12,986)
Cash Flows From Financing Activities:
Bridge facility financing fees	—		—		(40)
Proceeds from issuance of long-term debt	—		—		4,660
Repayment of long-term debt	(28)		(28)		(664)
Proceeds from (repayments of) intercompany note from the Utility	(145)		145		—
Common stock issued	—		—		7,582
Equity Units issued	—		—		1,304
Other	—		(29)		—
Net cash provided by (used in) financing activities	(173)		88		12,842
Net change in cash and cash equivalents	(1)		(97)		(225)
Cash and cash equivalents at January 1	126		223		448
Cash and cash equivalents at December 31	$	125	$	126	$	223
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(233)	$	(207)	$	(105)
Income taxes, net	—		1		—
Supplemental disclosures of noncash investing and financing activities
Common stock issued in satisfaction of liabilities	—		—		8,276
Changes to PG&E Corporation common stock and treasury stock in connection     with the Share Exchange and Tax Matters Agreement	(2,337)		4,854		—

(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock.

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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2022

SEC Schedule, 12-09, 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, 2022, 2021, and 2020

(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:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(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, 2022, 2021, and 2020

(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:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(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 (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

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 through 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.

Cash, Cash Equivalents, and Restricted Cash

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. As of December 31, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

Revenue Recognition

Revenue from Contracts with Customers

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. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. 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, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. 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. As a result, these differences have no impact on net income.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022.

PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

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.

Inventories

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, 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.

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 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, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020.  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 cost 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 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.

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. For more information, see Note 4 below.

The Utility has not recorded a liability related to certain AROs 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, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 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 through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020.

The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022.

Nuclear Decommissioning Obligation and 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 through rates and are held in trusts until authorized for release by the CPUC.The Utility classifies its debt 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 to or recoverable from, respectively, 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.

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.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred.

Senate Bill 846

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE's Civil Nuclear Credit Program” below). Under the loan agreement, the DWR will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements.

U.S. DOE’s Civil Nuclear Credit ProgramOn November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense on the Consolidated Statements of Income as eligible costs are incurred.

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.  

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below.

Non-Consolidated VIEs

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 as of December 31, 2022, 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 or 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 as of December 31, 2022, it did not consolidate any of them.

Voluntary Separation Program

In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets.

Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted

Debt

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Reference Rate Reform

On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Earnings Per Share

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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.

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 rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and 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 through 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Summary of Revenues Disaggregated by Type of Customer

The following table presents the Utility’s revenues disaggregated by type of customer:

	Year Ended December 31,
(in millions)	2022		2021
Electric
Revenue from contracts with customers
Residential	$	6,130	$	6,089
Commercial	5,416		5,042
Industrial	1,626		1,493
Agricultural	1,830		1,565
Public street and highway lighting	77		73
Other, net (1)	(247)		(84)
Total revenue from contracts with customers - electric	14,832		14,178
Regulatory balancing accounts (2)	228		953
Total electric operating revenue	$	15,060	$	15,131
Natural gas
Revenue from contracts with customers
Residential	$	3,353	$	2,759
Commercial	1,005		713
Transportation service only	1,534		1,346
Other, net (1)	163		140
Total revenue from contracts with customers - gas	6,055		4,958
Regulatory balancing accounts (2)	565		553
Total natural gas operating revenue	6,620		5,511
Total operating revenues	$	21,680	$	20,642

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment

The Utility’s estimated service lives of its property, plant, and equipment were as follows:

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2022		2021
Electricity generating facilities (1)	5 to 75	$	11,781	$	11,217
Electricity distribution facilities	10 to 70	41,061		37,723
Electricity transmission facilities	15 to 75	16,413		15,516
Natural gas distribution facilities	20 to 60	15,366		14,100
Natural gas transmission and storage facilities	5 to 66	9,859		9,067
Financing lease		18		18
Construction work in progress		4,137		3,480
General plant and other	5 to 50	8,518		7,838
Total property, plant, and equipment		107,153		98,959
Accumulated depreciation		(30,946)		(29,131)
Net property, plant, and equipment (2)		$	76,207	$	69,828

(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 16 below.(2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below.

Changes In Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations:

(in millions)	2022		2021
ARO liability at beginning of year	$	5,298	$	6,412
Liabilities incurred	134		—
Revision in estimated cash flows	325		(1,378)
Accretion	213		287
Liabilities settled	(58)		(23)
ARO liability at end of year	$	5,912	$	5,298

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, 2022 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassifications:
Loss on investments (net of taxes of $0, $0 and $3, respectively)	—		—		(6)		(6)
Unrecognized net actuarial gain (net of taxes of $102, $99 and $0, respectively)	263		(255)		—		8
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively)	(242)		255		—		13
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1, $2 and $0, respectively) (1)	(3)		5		—		2
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively) (1)	1		(29)		—		(28)
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1)	2		24		—		26
Net current period other comprehensive income (loss)	21		—		(6)		15
Ending balance	$	(12)	$	18	$	(6)	$	—

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 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, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively)(1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 13 below for additional details.

Schedule of Lease Expense

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:

	Year Ended December 31,
(in millions)	2022		2021
Operating lease fixed cost	$	500	$	578
Operating lease variable cost	1,829		1,782
Total operating lease costs	$	2,329	$	2,360

Schedule of Future Expected Operating Lease Payments

At December 31, 2022, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2022
2023	$	307
2024	150
2025	146
2026	143
2027	142
Thereafter	2,196
Total lease payments	3,084
Less imputed interest	(1,610)
Total	$	1,474

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)

12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2022		2021
Pension benefits (1)	$	120	$	708	Indefinitely
Environmental compliance costs	1,193		1,089		32 years
Utility retained generation (2)	86		133		4 years
Price risk management	177		216		17 years
Catastrophic event memorandum account (3)	1,085		1,119		1 - 3 years
Wildfire expense memorandum account (4)	439		347		TBD years
Fire hazard prevention memorandum account (5)	79		75		1 - 3 years
Fire risk mitigation memorandum account (6)	65		44		1 - 3 years
Wildfire mitigation plan memorandum account (7)	756		424		1 - 3 years
Deferred income taxes (8)	2,730		1,849		51 years
Insurance premium costs (9)	99		207		2 - 4 years
Wildfire mitigation balancing account (10)	327		273		1 - 3 years
Vegetation management balancing account (11)	2,276		1,411		1 - 3 years
COVID-19 pandemic protection memorandum accounts (12)	26		49		TBD years
Microgrid memorandum account (13)	213		163		1 - 3 years
Financing costs (14)	211		175		Various
SB 901 securitization (15)	5,378		—		30 years
AROs in excess of recoveries (16)	120		—		Various
Other	1,063		925		Various
Total long-term regulatory assets	$	16,443	$	9,207

(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) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 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) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2022 and 2021, $44 million and $49 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.

(6) Includes costs primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. Recovery of WMPMA costs is subject to CPUC review and approval.

(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.

(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2022. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.

(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.

(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date.

(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below.

(16) 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 asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  See Note 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2022		2021
Cost of removal obligations (1)	$	7,773	$	7,306
Recoveries in excess of AROs (2)	—		388
Public purpose programs (3)	1,062		946
Employee benefit plans (4)	904		1,229
Transmission tower wireless licenses (5)	430		446
SFGO sale (6)	264		343
SB 901 securitization (7)	5,800		—
Other	1,397		1,341
Total long-term regulatory liabilities	$	17,630	$	11,999

(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.

(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 held 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 12 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.

(4) Represents cumulative differences between incurred costs and amounts collected in rates for post-retirement medical, post-retirement life and long-term disability plans.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.

(7) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement. See Note 6 below.

Current Regulatory Balancing Accounts Receivable

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

	Receivable Balance at December 31,
(in millions)	2022		2021
Electric distribution (1)	$	448	$	—
Gas distribution and transmission (2)	72		—
Energy procurement (3)	684		310
Public purpose programs (4)	358		321
Fire hazard prevention memorandum account (5)	—		50
Fire risk mitigation memorandum account (6)	—		14
Wildfire mitigation plan memorandum account (7)	—		67
Wildfire mitigation balancing account (8)	2		91
General rate case memorandum accounts (9)	3		468
Vegetation management balancing account (10)	137		127
Insurance premium costs (11)	602		605
Wildfire expense memorandum account (12)	—		440
Residential uncollectibles balancing accounts (13)	126		127
Catastrophic event memorandum account	144		—
Other	688		379
Total regulatory balancing accounts receivable	$	3,264	$	2,999

Current Regulatory Balancing Accounts Payable

	Payable Balance at December 31,
(in millions)	2022		2021
Electric distribution (1)	$	—	$	121
Electric transmission (14)	228		24
Gas distribution and transmission (2)	66		83
Energy procurement (3)	428		211
Public purpose programs (4)	272		259
Nuclear decommissioning adjustment mechanism (15)	8		137
SFGO sale	152		21
Other	504		265
Total regulatory balancing accounts payable	$	1,658	$	1,121

(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(2) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings. 

(3) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. 

(4) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery.

(9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC.

(10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery.

(11) The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets.

(12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022.

(13) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers.

(14) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.

(15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant.

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DEBT (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2022:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2027	$	4,400	(1)	$	(1,930)	$	(998)	$	1,472
Utility receivables securitization program (2)	September 2024	1,389		(3)	(1,184)		—		205		(3)
PG&E Corporation revolving credit facility	June 2025	500			—		—		500
Total credit facilities		$	6,289		$	(3,114)	$	(998)	$	2,177

(1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Schedule of Long-term Debt

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2022		December 31, 2021
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,681	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of unamortized discount and debt issuance costs		(28)		(26)
Unamortized discount/premium and debt issuance costs, net		(66)		(90)
Total PG&E Corporation Long-Term Debt		4,587		4,593
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	—		500
2022	1.75%	—		2,500
2023	1.70% - 4.25%	2,075		3,575
2024	3.25% - 3.75%	1,800		800
2025	3.45% - 4.95%	1,925		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		2,550
2028	3.00% - 4.65%	1,975		1,975
2029	4.20%	400		—
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		—
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		700
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
2052	5.25%	550		—
Less: current portion, net of unamortized discount and debt issuance costs		(2,072)		(2,996)
Unamortized discount, premium and debt issuance costs, net		(195)		(190)
Total Utility First Mortgage Bonds		32,135		31,816
Recovery Bonds (3)		9,292		860
Less: current portion		(168)		(18)
DWR Loan (4)		312		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2024	variable rate (5)	1,184		974
2-Year Term Loan - Stated Maturity: 2024	variable rate (6)	400		—
18-month Term Loan - Stated Maturity: 2023	variable rate (7)	—		1,441
Less: current portion		—		(1,441)
Total Utility Long-Term Debt		43,155		33,632
Total PG&E Corporation Consolidated Long-Term Debt		$	47,742	$	38,225

(1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively.

(2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates.

(4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance.

(5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%.

(6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%.

(7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022.

Schedule Of Long Term Debt Repayments

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below:

(in millions, except interest rates)	2023			2024			2025			2026			2027			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2022	7.13		%	7.13		%	7.13		%	—		%	—		%	—		%	7.13		%
Variable rate obligations	$	28		$	28		$	2,625		$	—		$	—		$	—		$	2,681
Utility (1)
Average fixed interest rate	2.91		%	3.40		%	3.82		%	3.10		%	3.22		%	4.12		%	3.84		%
Fixed rate obligations	$	2,075		$	1,800		$	1,925		$	2,551		$	3,000		$	23,051		$	34,402
Variable interest rate as of December 31, 2022	—		%	5.54		%	—		%	—		%	—		%	—		%	5.54		%
Variable rate obligations	$	—		$	1,584		$	—		$	—		$	—		$	—		$	1,584
Recovery Bonds (2)
AB 1054 obligations	$	38		$	46		$	48		$	50		$	51		$	1,592		$	1,825
SB 901 obligations	$	130		$	129		$	135		$	141		$	146		$	6,786		$	7,467
Total consolidated debt	$	2,271		$	3,587		$	4,733		$	2,742		$	3,197		$	33,429		$	49,959

(1) The balance excludes DWR loan, see Note 3 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6.

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Debt

The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Final Maturity Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

Schedule of Financial Statement Impact of Securitization

The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities:

SB 901 securitization regulatory asset (in millions)
Regulatory asset balance at inception	$	5,500
Amortization	(122)
Balance at December 31, 2022	$	5,378

SB 901 securitization regulatory liability (in millions)
Regulatory liability balance at inception	$	(5,540)
Amortization	308
Additions	(568)
Balance at December 31, 2022	$	(5,800)

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COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2022

Common Stock And Share-Based Compensation [Abstract]

Schedule of Compensation Expense for Share-based Incentive Awards

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2022:

(in millions)	2022		2021		2020
Stock Options	$	—	$	—	$	3
Restricted stock units	60		35		15
Performance shares	55		21		17
Total compensation expense (pre-tax)	$	115	$	56	$	35
Total compensation expense (after-tax)	$	83	$	40	$	25

Summary of Stock Option Activity

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,195,834	$	7.42		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(43,702)	10.23			—
Outstanding at December 31	2,152,132	7.36		2.41	—
Vested or expected to vest at December 31	2,152,132	7.36		2.41	—
Exercisable at December 31	2,152,132	$	7.36	2.41	$	—

(1) Represents additional payout of existing stock option grants.

Schedule of Restricted Stock Units

The following table summarizes restricted stock unit activity for 2022:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	10,090,375	$	11.00
Granted	5,850,945	11.40
Vested	(4,175,008)	10.96
Forfeited	(788,192)	11.18
Nonvested at December 31	10,978,120	$	11.21

Schedule of Performance Shares

The following table summarizes activity for performance shares in 2022:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	8,567,009	$	9.64
Granted	3,105,604	13.44
Vested	—	—
Forfeited	(650,559)	10.15
Nonvested at December 31	11,022,054	$	10.68

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method

The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2022, 2021, and 2020.

	Year Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Income (loss) available for common shareholders	$	1,800	$	(102)	$	(1,318)
Weighted average common shares outstanding, basic	1,987		1,985		1,257
Add incremental shares from assumed conversions:
Employee share-based compensation	8		—		—
Equity Units	137		—		—
Weighted average common shares outstanding, diluted	2,132		1,985		1,257
Total earnings (loss) per common share, diluted	$	0.84	$	(0.05)	$	(1.05)

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2022		2021		2020		2022		2021		2020
Current:
Federal	$	(1)	$	—	$	(26)	$	(1)	$	—	$	(26)
State	—		1		(34)		—		—		(34)
Deferred:
Federal	(943)		543		258		(852)		588		290
State	(389)		296		171		(348)		316		185
Tax credits	(5)		(4)		(7)		(5)		(4)		(7)
Income tax provision (benefit)	$	(1,338)	$	836	$	362	$	(1,206)	$	900	$	408

Schedule of Deferred Tax Assets and Liabilities

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2022		2021		2022		2021
Deferred income tax assets:
Tax carryforwards	$	7,156	$	5,628	$	6,868	$	5,425
Compensation	157		185		80		108
Greenhouse gas allowance	239		157		239		157
Wildfire-related claims (1)	1,489		1,723		1,489		1,723
Operating lease liability	368		346		368		346
Transmission tower wireless licenses	254		266		254		266
Other (2)	197		121		177		136
Total deferred income tax assets	$	9,860	$	8,426	$	9,475	$	8,161
Deferred income tax liabilities:
Property related basis differences	9,374		8,847		9,363		8,835
Regulatory balancing accounts	1,376		1,193		1,376		1,193
Debt financing costs	465		501		465		501
Operating lease right of use asset	368		346		368		346
Income tax regulatory asset (3)	764		517		764		517
Other (4)	245		199		230		178
Total deferred income tax liabilities	$	12,592	$	11,603	$	12,566	$	11,570
Total net deferred income tax liabilities	$	2,732	$	3,177	$	3,091	$	3,409

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service area over the past several years.

(2) Amounts include benefits, state taxes, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

Schedule of Effective Income Tax Rate Reconciliation

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,
	2022		2021		2020		2022		2021		2020
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(75.8)		31.3		(15.3)		(26.9)		24.1		19.1
Effect of regulatory treatment of fixed asset differences (2)	(123.8)		(71.5)		39.0		(49.2)		(51.6)		(44.9)
Tax credits	(3.2)		(1.7)		1.5		(1.3)		(1.2)		(1.7)
Fire Victim Trust (3)	(160.9)		127.3		(44.9)		(64.0)		91.9		51.7
Bankruptcy and emergence	—		—		(37.6)		—		—		2.4
Other, net (4)	12.9		5.3		(2.1)		2.2		2.6		2.2
Effective tax rate	(329.8)	%	111.7	%	(38.4)	%	(118.2)	%	86.8	%	49.8	%

(1) Includes the effect of state flow-through ratemaking treatment.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  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.  In 2022, 2021, and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) The Utility includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs.

Schedule of Change in Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2022		2021		2020		2022		2021		2020
Balance at beginning of year	$	498	$	437	$	420	$	498	$	437	$	420
Reductions for tax position taken during a prior year	(1)		(23)		(43)		(1)		(23)		(43)
Additions for tax position taken during the current year	73		85		60		73		85		60
Settlements	—		(1)		—		—		(1)		—
Balance at end of year	$	570	$	498	$	437	$	570	$	498	$	437

Schedule of Operating Loss and Tax Credit Carryforward Balances

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

(in millions)	December 31, 2022		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,447	2031 - 2036
Net operating loss carryforward - Post-2017	23,170		N/A
Tax credit carryforward	152		2029 - 2041
State:
Net operating loss carryforward	$	25,169	2039 - 2041
Tax credit carryforward	126		Various

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Volumes of Outstanding Derivative Contracts

The volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume at
Underlying Product	Instruments	December 31, 2022	December 31, 2021
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	171,212,813	173,361,635
	Options	27,785,000	14,420,000
Electricity (MWh)	Forwards, Futures and Swaps	10,814,728	10,283,639
	Options	215,600	288,000
	Congestion Revenue Rights (3)	205,743,505	239,857,610

(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.

Offsetting Liabilities

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

As of December 31, 2021, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

Offsetting Assets

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

As of December 31, 2021, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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, 2022
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	658	$	—	$	—	$	—	$	658
Fixed-income securities	—		49		—		—		49
Nuclear decommissioning trusts
Short-term investments	117		—		—		—		117
Global equity securities	1,845		—		—		—		1,845
Fixed-income securities	1,094		791		—		—		1,885
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,056		791		—		—		3,872
Customer credit trust
Short-term investments	19		—		—		—		19
Global equity securities	218		—		—		—		218
Fixed-income securities	216		292		—		—		508
Total customer credit trust	453		292		—		—		745
Price risk management instruments (Note 11)
Electricity	—		94		432		40		566
Gas	—		604		—		327		931
Total price risk management instruments	—		698		432		367		1,497
Rabbi trusts
Short-term investments	25		—		—		—		25
Global equity securities	5		—		—		—		5
Fixed-income securities	—		69		—		—		69
Life insurance contracts	—		64		—		—		64
Total rabbi trusts	30		133		—		—		163
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	10		—		—		—		143
TOTAL ASSETS	$	4,207	$	1,963	$	432	$	367	$	7,127
Liabilities:
Price risk management instruments (Note 11)
Electricity	$	—	$	10	$	233	$	(20)	$	223
Gas	—		172		—		(166)		6
TOTAL LIABILITIES	$	—	$	182	$	233	$	(186)	$	229

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

(2) Represents amount before deducting $575 million primarily related to deferred taxes on appreciation of investment value. 

	Fair Value Measurements
	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurement Inputs and Valuation Techniques

	Fair Value at
(in millions)	At December 31, 2022				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	305	$	138	Market approach	CRR auction prices	$ (145.09) - 2,724.93 / 0.89
Power purchase agreements	$	127	$	95	Discounted cash flow	Forward prices	$ (6.39) - 286.75 / 78.14

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2022 and 2021, respectively:

	Price Risk Management Instruments
(in millions)	2022		2021
Liability balance as of January 1	$	(34)	$	(72)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	233		38
Asset (Liability) balance as of December 31	$	199	$	(34)

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Carrying Amount and Fair Value of Financial Instruments

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At December 31, 2022				At December 31, 2021
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,355	$	4,490	$	4,619	$	4,796
Utility	32,847		27,666		31,816		35,803

Schedule of Unrealized Gains (Losses) Related to Available-for-sale Investments

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Nuclear decommissioning trusts
Short-term investments	$	117	$	—	$	—	$	117
Global equity securities	413		1,468		(11)		1,870
Fixed-income securities	1,991		10		(116)		1,885
Total (1)	$	2,521	$	1,478	$	(127)	$	3,872
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581

(1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule of Available for Sale Securities Table

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

	As of
(in millions)	December 31, 2022
Less than 1 year	$	42
1–5 years	624
5–10 years	400
More than 10 years	819
Total maturities of fixed-income securities	$	1,885

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2022
Customer credit trust
Short-term investments	$	19	$	—	$	—	$	19
Global equity securities	219		13		(14)		218
Fixed-income securities	516		—		(8)		508
Total	$	754	$	13	$	(22)	$	745

Schedule of Activity for Debt and Equity Securities

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

(in millions)	2022		2021		2020
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	3,316	$	1,678	$	1,518
Gross realized gains on securities	2		286		159
Gross realized losses on securities	(3)		(19)		(41)

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

	As of
(in millions)	December 31, 2022
Less than 1 year	$	79
1–5 years	123
5–10 years	120
More than 10 years	186
Total maturities of fixed-income securities	$	508

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

(in millions)	2022
Proceeds from sales and maturities of customer credit trust investments	$	250
Gross realized gains on securities	10
Gross realized losses on securities (1)	(41)

(1) Includes $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2022.

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2022

Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]

Reconciliation of Changes 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 2022 and 2021:

Pension Plan

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	21,895	$	20,759
Actual return on plan assets	(4,916)		1,693
Company contributions	339		335
Benefits and expenses paid	(949)		(892)
Fair value of plan assets at end of year	$	16,369	$	21,895
Change in benefit obligation:
Benefit obligation at beginning of year	$	22,759	$	23,172
Service cost for benefits earned	575		587
Interest cost	692		645
Actuarial gain (1)	(6,471)		(752)
Plan amendments	—		—
Benefits and expenses paid	(947)		(893)
Benefit obligation at end of year (2)	$	16,608	$	22,759
Funded Status:
Current liability	$	(8)	$	(9)
Noncurrent liability	(231)		(856)
Net liability at end of year	$	(239)	$	(865)

(1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2022		2021
Change in plan assets:
Fair value of plan assets at beginning of year	$	3,102	$	2,995
Actual return on plan assets	(693)		193
Company contributions	26		10
Plan participant contribution	81		80
Benefits and expenses paid	(180)		(176)
Fair value of plan assets at end of year	$	2,336	$	3,102
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,766	$	1,876
Service cost for benefits earned	62		63
Interest cost	53		51
Actuarial gain (1)	(486)		(152)
Benefits and expenses paid	(162)		(156)
Federal subsidy on benefits paid	3		4
Plan participant contributions	81		80
VSP related termination benefits (3)	22		—
Benefit obligation at end of year	$	1,339	$	1,766
Funded Status: (2)
Noncurrent asset	$	997	$	1,340
Noncurrent liability	—		(4)
Net asset at end of year	$	997	$	1,336

(1) The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes

(2) At December 31, 2022 and 2021, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively.

(3) Represents VSP-related credits to employee retirement health savings accounts. See Note 3 above.

Components of Net Periodic Benefit Cost

Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	575	$	587	$	530
Interest cost	692		645		713
Expected return on plan assets	(1,189)		(1,046)		(1,044)
Amortization of prior service cost	(4)		(6)		(6)
Amortization of net actuarial loss	2		6		3
Net periodic benefit cost	76		186		196
Less: transfer to regulatory account (2)	254		147		136
Total expense recognized	$	330	$	333	$	332

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2022		2021		2020
Service cost for benefits earned (1)	$	62	$	63	$	61
Interest cost	53		51		63
Expected return on plan assets	(130)		(137)		(138)
Amortization of prior service cost	7		14		14
Amortization of net actuarial loss	(40)		(33)		(21)
Special termination benefits	22		—		—
Net periodic benefit cost	$	(26)	$	(42)	$	(21)

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2022		2021		2020		2022	2021	2020
Discount rate	5.54	%	3.03	%	2.77	%	5.50 - 5.54%	2.97 - 3.04%	2.67 - 2.80%
Rate of future compensation increases	3.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.10	%	5.50	%	5.10	%	3.70 - 7.30%	3.30 - 6.40%	3.10 - 6.10%
Interest crediting rate for cash balance plan	4.19	%	1.95	%	1.95	%	N/A	N/A	N/A

Target Asset Allocation Percentages

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

	Pension Plan						PBOP Plans
	2023		2022		2021		2023		2022		2021
Global equity securities	26	%	30	%	30	%	28	%	26	%	36	%
Absolute return	1	%	2	%	2	%	1	%	1	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	5	%
Fixed-income securities	65	%	60	%	60	%	68	%	70	%	58	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Schedule of Changes in Fair Value of Plan Assets

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2022 and 2021.

	Fair Value Measurements
	At December 31,
	2022								2021
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	461	$	126	$	—	$	587	$	552	$	255	$	—	$	807
Global equity securities	1,430		—		—		1,430		2,074		424		—		2,498
Absolute Return	—		—		—		—		—		1		—		1
Real assets	426		—		—		426		632		—		—		632
Fixed-income securities	1,946		6,086		8		8,040		2,729		7,388		27		10,144
Assets measured at NAV	—		—		—		5,886		—		—		—		7,972
Total	$	4,263	$	6,212	$	8	$	16,369	$	5,987	$	8,068	$	27	$	22,054
PBOP Plans:
Short-term investments	$	26	$	—	$	—	$	26	$	31	$	—	$	—	$	31
Global equity securities	83		—		—		83		105		—		—		105
Real assets	29		—		—		29		34		—		—		34
Fixed-income securities	406		702		1		1,109		776		875		1		1,652
Assets measured at NAV	—		—		—		1,100		—		—		—		1,296
Total	$	544	$	702	$	1	$	2,347	$	946	$	875	$	1	$	3,118
Total plan assets at fair value							$	18,716							$	25,172

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, 2022 and 2021:

(in millions)
For the year ended December 31, 2022	Fixed-Income
Balance at beginning of year	$	27
Actual return on plan assets:
Relating to assets still held at the reporting date	1
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	(26)
Balance at end of year	$	8
(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27

Schedule of Estimated Benefits Expected to be Paid

As of December 31, 2022, 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:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2023	907	97	(4)
2024	996	98	(4)
2025	1028	100	(4)
2026	1057	94	(4)
2027	1,082	94	(4)
Thereafter in the succeeding five years	5,702	475	(4)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Schedule of Significant Related Party Transactions

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2022		2021		2020
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	104	$	82	$	108
Utility employee benefit due to PG&E Corporation	85		39		34

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WILDFIRE-RELATED CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Summary of Wildfire-Related Claims

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	769
Accrued Losses	225
Payments	(344)
Balance at December 31, 2022	$	650

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	211
Accrued Losses	25
Payments	(204)
Balance at December 31, 2022	$	32

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021	$	1,150
Accrued Losses	25
Payments	(44)
Balance at December 31, 2022	$	1,131

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2022 are:

Potential Recovery Source (in millions)	2022 Mosquito fire		2021 Dixie fire
Insurance	$	45	$	530
FERC TO rates	10		115
WEMA	50		388
Wildfire Fund	—		175
Probable recoveries at December 31, 2022	$	105	$	1,208

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2021	$	—	$	563	$	270	$	414	$	1,247
Accrued insurance recoveries (1)	45		(33)		33		—		45
Reimbursements	—		—		(185)		(313)		(498)
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794

(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

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OTHER CONTINGENCIES AND COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Schedule of Environmental Remediation Liability

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

	Balance at
(in millions)	December 31, 2022		December 31, 2021
Topock natural gas compressor station	$	284	$	299
Hinkley natural gas compressor station	110		123
Former MGP sites owned by the Utility or third parties (1)	750		667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		104
Fossil fuel-fired generation facilities and sites (3)	26		70
Total environmental remediation liability	$	1,282	$	1,263

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.

(2) Primarily driven by geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

Schedule of Undiscounted Future Expected Power Purchase Agreement Payments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2022:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2023	$	2,081	$	482	$	60	$	1,746	$	47	$	4,416
2024	2,052		378		61		195		11		2,697
2025	2,040		715		61		140		—		2,956
2026	1,980		663		21		129		—		2,793
2027	1,919		579		7		53		—		2,558
Thereafter	17,807		1,565		13		—		—		19,385
Total purchase commitments	$	27,879	$	4,382	$	223	$	2,263	$	58	$	34,805

Schedule of Other Commitments

At December 31, 2022, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2023	$	88
2024	85
2025	83
2026	81
2027	80
Thereafter	3,518
Total minimum lease payments	$	3,935

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ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2022 numberOfSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

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BANKRUPTCY FILING (Chapter 11 Claims Process) (Details) notice in Thousands	Dec. 31, 2022 notice
Debt Instrument [Line Items]
Proofs of claims	100
Subrogation Wildfire Trust and Fire Victim Trust
Debt Instrument [Line Items]
Proofs of claims	80

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (10K Narrative) (Details) ft² in Thousands			1 Months Ended		3 Months Ended		12 Months Ended
	Nov. 17, 2022 USD ($)	Oct. 18, 2022 USD ($)	Nov. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) ft² employee	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) ft² facility employee	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Jan. 31, 2023 ft²	Sep. 02, 2022 USD ($)	Jul. 20, 2022 USD ($)	May 10, 2022 USD ($)	Nov. 12, 2021 USD ($)	Oct. 23, 2020 USD ($) ft²
Public Utility, Property, Plant and Equipment [Line Items]
Restricted cash				$ 16,000,000	$ 213,000,000	$ 16,000,000	$ 213,000,000	$ 16,000,000
Period for probable revenue recovery							24 months
Allowance for credit loss decrease					88,000,000	207,000,000
Credit losses							$ 143,000,000	154,000,000
Decommissioning cost estimate				4,000,000,000
Asset retirement obligation				5,298,000,000	5,912,000,000	5,298,000,000	5,912,000,000	5,298,000,000	$ 6,412,000,000
Decrease in decommissioning cost				1,300,000,000
Decrease in decommissioning cost, un-escalated				378,000,000
Decrease in decommissioning cost, escalated				2,600,000,000
Increase (decrease) in asset retirement obligation							$ 614,000,000
Government Assistance, Statement of Income or Comprehensive Income [Extensible Enumeration]							Operating and maintenance
Litigation liability, current					193,000,000		$ 193,000,000
Wildfire Fund asset				461,000,000	460,000,000	461,000,000	460,000,000	461,000,000
Litigation contribution, net					4,800,000,000		4,800,000,000
Amortization and accretion							477,000,000	517,000,000	$ 413,000,000
Insurance receivable				1,247,000,000	$ 794,000,000	1,247,000,000	$ 794,000,000	1,247,000,000
Number of eligible employees | employee					470		470
Lease payments							$ 2,300,000,000	2,400,000,000
Operating lease right of use asset				$ 1,234,000,000	$ 1,311,000,000	$ 1,234,000,000	1,311,000,000	$ 1,234,000,000
Operating lease, right-of-use liability					$ 1,474,000,000		$ 1,474,000,000
Weighted average remaining lease term				6 years 14 days	19 years 7 months 6 days	6 years 14 days	19 years 7 months 6 days	6 years 14 days
Weighted average discount rate				6.10%	6.50%	6.10%	6.50%	6.10%
CAPP Funding
Public Utility, Property, Plant and Equipment [Line Items]
Disbursement			$ 200,000,000
Performance-Based Disbursement
Public Utility, Property, Plant and Equipment [Line Items]
Disbursement		$ 7
Maximum disbursement		300,000,000
Performance-Based Disbursement | Utilities Operating Expense, Maintenance and Operations
Public Utility, Property, Plant and Equipment [Line Items]
Reimbursement amount							$ 38,000,000
Civil Nuclear Credit Program
Public Utility, Property, Plant and Equipment [Line Items]
Disbursement	$ 1,100,000,000
Long-Term Debt | Performance-Based Disbursement
Public Utility, Property, Plant and Equipment [Line Items]
Reimbursement amount							312,000,000
Other Current Liabilities
Public Utility, Property, Plant and Equipment [Line Items]
Wildfire fund, noncurrent					$ 935,000,000		935,000,000
One-time Termination Benefits
Public Utility, Property, Plant and Equipment [Line Items]
Severance costs							80,000,000
Credits to employee retirement health savings accounts							22,000,000
2021 Dixie fire
Public Utility, Property, Plant and Equipment [Line Items]
Insurance receivable				$ 563,000,000	530,000,000	$ 563,000,000	530,000,000	$ 563,000,000
2021 Dixie fire | Other noncurrent assets – other
Public Utility, Property, Plant and Equipment [Line Items]
Insurance receivable					175,000,000		175,000,000
Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts				2,999,000,000	3,264,000,000	2,999,000,000	3,264,000,000	2,999,000,000
COVID-19 Pandemic protection memorandum account
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets				30,000,000	3,000,000	30,000,000	3,000,000	30,000,000
FERC TO rates
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets				12,000,000	8,000,000	12,000,000	8,000,000	12,000,000
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts				127,000,000	126,000,000	127,000,000	$ 126,000,000	127,000,000
Wildfire Fund Asset
Public Utility, Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life							15 years
Recovery Bonds | Secured Debt
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount				860,000,000	1,800,000,000	860,000,000	$ 1,800,000,000	860,000,000						$ 860,000,000
Long-term debt, gross				860,000,000	9,292,000,000	860,000,000	9,292,000,000	860,000,000
Series 2022-A Recovery Bonds
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount			$ 983,000,000
SB 901 Securitization | Secured Debt
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount					7,500,000,000		7,500,000,000					$ 3,900,000,000	$ 3,600,000,000
Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Restricted cash				16,000,000	213,000,000	16,000,000	$ 213,000,000	$ 16,000,000
Composite depreciation rate							3.74%	3.82%	3.76%
AFUDC debt recorded							$ 81,000,000	$ 56,000,000	$ 35,000,000
AFUDC equity recorded							184,000,000	133,000,000	140,000,000
Nuclear decommissioning obligation accrued							4,100,000,000	3,900,000,000
Decommissioning cost estimate							7,100,000,000	7,600,000,000
Wildfire Fund asset				461,000,000	460,000,000	461,000,000	460,000,000	461,000,000
Amortization and accretion					477,000,000	517,000,000	477,000,000	517,000,000	$ 413,000,000
Operating lease right of use asset				1,232,000,000	$ 1,311,000,000	1,232,000,000	$ 1,311,000,000	1,232,000,000
Pacific Gas & Electric Co (Utility) | Oakland Headquarters Lease
Public Utility, Property, Plant and Equipment [Line Items]
Rentable square feet | ft²					488		488								910
Lease, option payment letter of credit															$ 75,000,000
Lease, security letter of credit															75,000,000
Purchase options, land, value															$ 892,000,000
Operating lease right of use asset					$ 535,000,000		$ 535,000,000
Leasehold improvements					214,000,000		214,000,000
Leasehold incentives					137,000,000		137,000,000
Operating lease, right-of-use liability					672,000,000		672,000,000
Pacific Gas & Electric Co (Utility) | Oakland Headquarters Lease | Subsequent Event
Public Utility, Property, Plant and Equipment [Line Items]
Rentable square feet | ft²										110
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program
Public Utility, Property, Plant and Equipment [Line Items]
Long-term debt, gross				974,000,000	1,184,000,000	974,000,000	$ 1,184,000,000	974,000,000
Pacific Gas & Electric Co (Utility) | Senate Bill 846
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount		$ 1,100,000,000
Pacific Gas & Electric Co (Utility) | Senate Bill 846 | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount											$ 1,400,000,000
Pacific Gas & Electric Co (Utility) | Diablo Canyon
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility							2
Pacific Gas & Electric Co (Utility) | Humboldt Bay
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility							1
PG&E AR Facility, LLC (SPV) | Receivables Securitization Program
Public Utility, Property, Plant and Equipment [Line Items]
Accounts receivable, net				$ 3,300,000,000	$ 3,600,000,000	$ 3,300,000,000	$ 3,600,000,000	$ 3,300,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Abstract]
Total operating revenues	$ 21,680	$ 20,642	$ 18,469
Electric
Disaggregation of Revenue [Abstract]
Total operating revenues	15,060	15,131	13,858
Natural gas
Disaggregation of Revenue [Abstract]
Total operating revenues	6,620	5,511	4,611
Pacific Gas & Electric Co (Utility)
Disaggregation of Revenue [Abstract]
Total operating revenues	21,680	20,642	18,469
Pacific Gas & Electric Co (Utility) | Electric
Disaggregation of Revenue [Abstract]
Total operating revenues	14,832	14,178
Regulatory balancing accounts	228	953
Total operating revenues	15,060	15,131	13,858
Pacific Gas & Electric Co (Utility) | Electric | Residential
Disaggregation of Revenue [Abstract]
Total operating revenues	6,130	6,089
Pacific Gas & Electric Co (Utility) | Electric | Commercial
Disaggregation of Revenue [Abstract]
Total operating revenues	5,416	5,042
Pacific Gas & Electric Co (Utility) | Electric | Industrial
Disaggregation of Revenue [Abstract]
Total operating revenues	1,626	1,493
Pacific Gas & Electric Co (Utility) | Electric | Agricultural
Disaggregation of Revenue [Abstract]
Total operating revenues	1,830	1,565
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting
Disaggregation of Revenue [Abstract]
Total operating revenues	77	73
Pacific Gas & Electric Co (Utility) | Electric | Other, net
Disaggregation of Revenue [Abstract]
Total operating revenues	(247)	(84)
Pacific Gas & Electric Co (Utility) | Natural gas
Disaggregation of Revenue [Abstract]
Total operating revenues	6,055	4,958
Regulatory balancing accounts	565	553
Total operating revenues	6,620	5,511	$ 4,611
Pacific Gas & Electric Co (Utility) | Natural gas | Residential
Disaggregation of Revenue [Abstract]
Total operating revenues	3,353	2,759
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial
Disaggregation of Revenue [Abstract]
Total operating revenues	1,005	713
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only
Disaggregation of Revenue [Abstract]
Total operating revenues	1,534	1,346
Pacific Gas & Electric Co (Utility) | Natural gas | Other, net
Disaggregation of Revenue [Abstract]
Total operating revenues	$ 163	$ 140

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utilities Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 107,153	$ 98,959
Accumulated depreciation	(30,946)	(29,131)
Net property, plant, and equipment	76,207	69,828
Electricity generating facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	11,781	11,217
Electricity generating facilities | Northern California Wildfire
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 1,800
Electricity generating facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Electricity generating facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	75 years
Electricity distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 41,061	37,723
Electricity distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	10 years
Electricity distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	70 years
Electricity transmission facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 16,413	15,516
Electricity transmission facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 years
Electricity transmission facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	75 years
Natural gas distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 15,366	14,100
Natural gas distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	20 years
Natural gas distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	60 years
Natural gas transmission and storage facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 9,859	9,067
Natural gas transmission and storage facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Natural gas transmission and storage facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	66 years
Financing lease
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 18	18
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	4,137	3,480
General plant and other
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 8,518	$ 7,838
General plant and other | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
General plant and other | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	50 years

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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, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability at beginning of year	$ 5,298	$ 6,412
Liabilities incurred	134	0
Revision in estimated cash flows	325	(1,378)
Accretion	213	287
Liabilities settled	(58)	(23)
ARO liability at end of year	$ 5,912	$ 5,298

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	$ 21,223	$ 21,253
Net current period other comprehensive gain (loss)	15	7
Ending balance	23,075	21,223
Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	21	6
Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	1
Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	(6)
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(15)	(22)
Ending balance	0	(15)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(33)	(39)
Ending balance	(12)	(33)
Accumulated Other Comprehensive Income (Loss) | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	18	17
Ending balance	18	18
Accumulated Other Comprehensive Income (Loss) | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	0
Ending balance	(6)	0
Amortization of net actuarial gain (loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Loss on investments	(6)
Other comprehensive income before reclassifications:	8	1,144
Amounts reclassified from other comprehensive income	28	20
Amortization of net actuarial gain (loss) | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, before reclassification	0
Loss on investments	0
Other comprehensive income before reclassifications, tax	102	391
Other comprehensive income before reclassifications:	263	1,007
Amount attributable to tax, reclassification	1	2
Amounts reclassified from other comprehensive income	(1)	(4)
Amortization of net actuarial gain (loss) | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, before reclassification	0
Loss on investments	0
Other comprehensive income before reclassifications, tax	99	53
Other comprehensive income before reclassifications:	(255)	137
Amount attributable to tax, reclassification	11	9
Amounts reclassified from other comprehensive income	29	24
Amortization of net actuarial gain (loss) | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, before reclassification	3
Loss on investments	(6)
Other comprehensive income before reclassifications, tax	0
Other comprehensive income before reclassifications:	0
Amount attributable to tax, reclassification	0
Amounts reclassified from other comprehensive income	0
Regulatory account transfer
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	13	(1,139)
Amounts reclassified from other comprehensive income	(26)	(16)
Regulatory account transfer | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications, tax	94	390
Other comprehensive income before reclassifications:	(242)	(1,003)
Amount attributable to tax, reclassification	0	1
Amounts reclassified from other comprehensive income	(2)	(2)
Regulatory account transfer | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications, tax	99	53
Other comprehensive income before reclassifications:	255	(136)
Amount attributable to tax, reclassification	9	5
Amounts reclassified from other comprehensive income	(24)	(14)
Regulatory account transfer | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications, tax	0
Other comprehensive income before reclassifications:	0
Amount attributable to tax, reclassification	0
Amounts reclassified from other comprehensive income	0
Amortization of prior service cost
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(6)
Amortization of prior service cost | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, reclassification	1	2
Amounts reclassified from other comprehensive income	3	4
Amortization of prior service cost | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, reclassification	2	4
Amounts reclassified from other comprehensive income	(5)	$ (10)
Amortization of prior service cost | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount attributable to tax, reclassification	0
Amounts reclassified from other comprehensive income	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Operating lease fixed cost	$ 500	$ 578
Operating lease variable cost	1,829	1,782
Total operating lease costs	$ 2,329	$ 2,360

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Future Expected Operating Lease Payments
2023	$ 307
2024	150
2025	146
2026	143
2027	142
Thereafter	2,196
Total lease payments	3,084
Less imputed interest	(1,610)
Total	$ 1,474

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Narrative) (Details) - USD ($) $ in Millions	Oct. 21, 2021	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Regulatory assets		$ 296.0	$ 496.0
Pacific Gas & Electric Co (Utility)
Regulatory Assets [Line Items]
Current regulatory liabilities		1,120.0	698.0
Deferral of current regulatory liabilities		604.0
Regulatory assets		296.0	496.0
Insurance premium costs
Regulatory Assets [Line Items]
Regulatory assets		$ 48.0	$ 82.0
Settlement recovery amount	$ 445.5

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jun. 30, 2022	Feb. 28, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Regulatory assets	$ 16,443			$ 9,207
Utility retained generation asset costs	1,200
Customer Harm Threshold, post-emergence transaction, recovery bonds issued			$ 7,500
Initial shareholder contribution	2,000
Pension benefits
Regulatory Assets [Line Items]
Regulatory assets	120			708
Environmental compliance costs
Regulatory Assets [Line Items]
Regulatory assets	$ 1,193			1,089
Recovery Period	32 years
Utility retained generation
Regulatory Assets [Line Items]
Regulatory assets	$ 86			133
Recovery Period	4 years
Price risk management
Regulatory Assets [Line Items]
Regulatory assets	$ 177			216
Recovery Period	17 years
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 1,085			1,119
Catastrophic event memorandum account | COVID-19
Regulatory Assets [Line Items]
Regulatory assets	$ 44			49
Catastrophic event memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Catastrophic event memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 439			347
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 79			75
Fire hazard prevention memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Fire hazard prevention memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 65			44
Fire risk mitigation memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Fire risk mitigation memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 756			424
Wildfire mitigation plan memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Wildfire mitigation plan memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	$ 2,730			1,849
Recovery Period	51 years
Insurance premium costs
Regulatory Assets [Line Items]
Regulatory assets	$ 99			207
Insurance premium costs | Minimum
Regulatory Assets [Line Items]
Recovery Period	2 years
Insurance premium costs | Maximum
Regulatory Assets [Line Items]
Recovery Period	4 years
Wildfire mitigation balancing account
Regulatory Assets [Line Items]
Regulatory assets	$ 327			273
Wildfire mitigation balancing account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Cost percentage threshold requiring approval	115.00%
Wildfire mitigation balancing account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Vegetation management balancing account
Regulatory Assets [Line Items]
Regulatory assets	$ 2,276			1,411
Cost percentage threshold requiring approval	120.00%
Vegetation management balancing account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Vegetation management balancing account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
COVID-19 Pandemic protection memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 26			49
COVID-19 pandemic protection memorandum account, undercollection bad debt
Regulatory Assets [Line Items]
Regulatory assets	4			30
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs
Regulatory Assets [Line Items]
Regulatory assets	22			19
Microgrid memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 213			163
Microgrid memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Microgrid memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Financing costs
Regulatory Assets [Line Items]
Regulatory assets	$ 211			175
SB 901 Securitization
Regulatory Assets [Line Items]
Regulatory assets	$ 5,378	$ 5,500		0
Recovery Period	30 years
Recoveries in excess of AROs
Regulatory Assets [Line Items]
Regulatory assets	$ 120			0
Other
Regulatory Assets [Line Items]
Regulatory assets	$ 1,063			$ 925

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 17,630		$ 11,999
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	430
Authorized amount of shareholder tax benefits to be returned	7,590
Federal Energy Regulatory Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	300
California Public Utilities Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	130
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	7,773		7,306
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	0		388
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	1,062		946
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	904		1,229
Transmission tower wireless licenses
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	430		446
SFGO sale
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	264		343
SB 901 Securitization
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	5,800	$ 5,540	0
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,397		$ 1,341

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 1,658	$ 1,121
Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	3,264	2,999
Electric distribution | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	0	121
Electric distribution | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	448	0
Electric transmission | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	228	24
Gas distribution and transmission | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	66	83
Gas distribution and transmission | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	72	0
Energy procurement | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	428	211
Energy procurement | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	684	310
Public purpose programs | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	272	259
Public purpose programs | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	358	321
Fire hazard prevention memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	0	50
Fire risk mitigation memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	0	14
Wildfire mitigation plan memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	0	67
Wildfire mitigation balancing account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	2	91
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	3	468
Vegetation management balancing account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	137	127
Insurance premium costs | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	602	605
Wildfire expense memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	0	440
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	126	127
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	8	137
Catastrophic event memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	144	0
SFGO sale | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	152	21
Other | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	504	265
Other | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 688	$ 379

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DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)	Dec. 31, 2022	Aug. 12, 2022	Apr. 20, 2022	Dec. 31, 2021	Jun. 22, 2021	Jul. 01, 2020
Revolving Credit Facility
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 6,289,000,000
Loans Outstanding	(3,114,000,000)
Letters of Credit Outstanding	(998,000,000)
Facility Availability	2,177,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	500,000,000					$ 500,000,000
Loans Outstanding	0
Letters of Credit Outstanding	0
Facility Availability	500,000,000
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	4,400,000,000				$ 4,000,000,000	$ 3,500,000,000
Loans Outstanding	(1,930,000,000)
Letters of Credit Outstanding	(998,000,000)
Facility Availability	1,472,000,000
Letter of credit sublimit	1,500,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	1,389,000,000	$ 1,500,000,000	$ 1,500,000,000
Loans Outstanding	(1,184,000,000)			$ (974,000,000)
Letters of Credit Outstanding	0
Facility Availability	205,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	1,000,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,500,000,000

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DEBT (Narrative) (Details)						12 Months Ended
	Oct. 04, 2022	Apr. 20, 2022 USD ($)	Mar. 31, 2022 USD ($)	Feb. 18, 2022 USD ($)	Jul. 01, 2020 USD ($) numberOfClaimHolder numberOfExtensionOption	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Jan. 06, 2023 USD ($)	Nov. 30, 2022 USD ($)	Aug. 12, 2022 USD ($)	Aug. 05, 2022 USD ($)	Jun. 08, 2022 USD ($)	Apr. 04, 2022 USD ($)	Mar. 11, 2022 USD ($)	Aug. 11, 2021 USD ($)	Jun. 22, 2021 USD ($)	May 11, 2021 USD ($)	Apr. 23, 2021 USD ($)	Apr. 30, 2020 USD ($)
Debt [Line Items]
Repayments of long-term debt						$ 5,968,000,000	$ 87,000,000	$ 764,000,000
Proceeds from the sale of long-term debt				$ 1,000,000,000
PG&E Corporation
Debt [Line Items]
Repayments of long-term debt						28,000,000	28,000,000	664,000,000
Nothern California Wild Fire
Debt [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized																		$ 7,500,000,000	$ 7,500,000,000	$ 7,500,000,000
Nothern California Wild Fire | Fire Risk Mitigation Capital Expenditures
Debt [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized						975,000,000						$ 1,400,000,000			$ 1,700,000,000
Customer Harm Threshold, post-emergence transaction, securitized, recorded															212,000,000
Customer Harm Threshold, post-emergence transaction, securitized, forecasted															1,160,000,000
Customer Harm Threshold, post-emergence transaction, securitized, pending															$ 350,000,000
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of long-term debt						5,941,000,000	59,000,000	$ 100,000,000
2020 Utility Term Loan Credit Agreement | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of long-term debt			$ 298,000,000
364-Day 2022A Tranche Loans | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross														$ 500,000,000
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross		$ 125,000,000
Credit spread adjustment		0.10%
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | SOFR
Debt [Line Items]
Basis spread on variable rate		1.25%
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | Base Rate
Debt [Line Items]
Basis spread on variable rate		0.25%
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross		$ 400,000,000
Credit spread adjustment		0.10%
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | SOFR
Debt [Line Items]
Basis spread on variable rate		1.25%
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | Base Rate
Debt [Line Items]
Basis spread on variable rate		0.25%
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 1,500,000,000				1,389,000,000					$ 1,500,000,000
Long-term debt, gross						1,184,000,000	974,000,000
Increase in facility limit		$ 500,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Line of credit facility, maximum borrowing capacity						1,000,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Line of credit facility, maximum borrowing capacity						1,500,000,000
Revolving Credit Facility
Debt [Line Items]
Line of credit facility, maximum borrowing capacity						6,289,000,000
Extension option, term	1 year
Long-term debt, gross						3,114,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 500,000,000	500,000,000
Number of extensions | numberOfExtensionOption					2
Extension option, term					1 year
Long-term debt, gross						0
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 3,500,000,000	4,400,000,000											$ 4,000,000,000
Number of extensions | numberOfClaimHolder					2
Extension option, term	1 year				1 year
Long-term debt, gross						1,930,000,000
Intercompany Loan
Debt [Line Items]
Debt instrument, face amount																$ 145,000,000
Series 2022-A Recovery Bonds
Debt [Line Items]
Debt instrument, face amount										$ 983,000,000
Series 2022-A Recovery Bonds | Tranche One
Debt [Line Items]
Debt instrument, face amount										$ 215,000,000
Interest rate										5.045%
Series 2022-A Recovery Bonds | Tranche Two
Debt [Line Items]
Debt instrument, face amount										$ 200,000,000
Interest rate										5.256%
Series 2022-A Recovery Bonds | Tranche Three
Debt [Line Items]
Debt instrument, face amount										$ 568,000,000
Interest rate										5.536%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross						$ 1,800,000,000	800,000,000
Debt instrument, face amount				$ 1,000,000,000
Interest rate				3.25%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Interest rate						3.25%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Interest rate						3.75%
First Mortgage Bonds, Stated Maturity 2029 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross						$ 400,000,000	0
Debt instrument, face amount				$ 400,000,000
Interest rate				4.20%		4.20%
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross						$ 1,050,000,000	0
Debt instrument, face amount				$ 450,000,000
Interest rate				4.40%
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Interest rate						4.40%
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Interest rate						5.90%
First Mortgage Bonds, Stated Maturity 2052 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross						$ 550,000,000	$ 0
Debt instrument, face amount				$ 550,000,000
Interest rate				5.25%		5.25%
4.950% Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount													$ 450,000,000
Interest rate													4.95%
5.450% Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount													$ 450,000,000
Interest rate													5.45%
5.90% Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount													$ 600,000,000
Interest rate													5.90%
First Mortgage Bonds Due 2033 | Pacific Gas & Electric Co (Utility) | Subsequent Event
Debt [Line Items]
Debt instrument, face amount									$ 750,000,000
Interest rate									6.15%
First Mortgage Bonds Due 2053 | Pacific Gas & Electric Co (Utility) | Subsequent Event
Debt [Line Items]
Debt instrument, face amount									$ 750,000,000
Interest rate									675.00%

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DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Feb. 18, 2022	Dec. 31, 2021	Nov. 12, 2021
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	$ (2,268)		$ (4,481)
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(2,241)		(4,455)
PG&E Corporation
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(27)		(27)
New Debt
Debt [Line Items]
Long-term debt, net	47,742		38,225
New Debt | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	0		(1,441)
Long-term debt, net	43,155		33,632
New Debt | PG&E Corporation
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(28)		(26)
Unamortized discount/premium and debt issuance costs, net	(66)		(90)
Long-term debt, net	4,587		4,593
Term Loan, Stated Maturity 2025 | PG&E Corporation
Debt [Line Items]
Long-term debt, gross	$ 2,681		$ 2,709
Term Loan, Stated Maturity 2025 | PG&E Corporation | LIBOR
Debt [Line Items]
Stated interest rate	7.44%		3.50%
Senior Notes Due 2028 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.00%
Long-term debt, gross	$ 1,000		$ 1,000
Senior Notes Due 2030 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.25%
Long-term debt, gross	$ 1,000		1,000
First Mortgage Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(2,072)		(2,996)
Unamortized discount/premium and debt issuance costs, net	(195)		(190)
Long-term debt, net	32,135		31,816
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 0		$ 500
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Stated interest rate			1.69%
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	1.75%
Long-term debt, gross	$ 0		$ 2,500
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,075		3,575
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	1.70%
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.25%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate		3.25%
Long-term debt, gross	$ 1,800		800
Recovery Bonds		$ 1,000
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.25%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.75%
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,925		1,475
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.45%
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.95%
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,551		2,551
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.95%
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.15%
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 3,000		2,550
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.10%
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	5.45%
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,975		1,975
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.00%
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.65%
First Mortgage Bonds, Stated Maturity 2029 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.20%	4.20%
Long-term debt, gross	$ 400		0
Recovery Bonds		$ 400
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.55%
Long-term debt, gross	$ 3,100		3,100
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 3,000		3,000
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.50%
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.25%
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate		4.40%
Long-term debt, gross	$ 1,050		0
Recovery Bonds		$ 450
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.40%
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	5.90%
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,951		2,951
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.30%
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.50%
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 700		700
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.20%
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.50%
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 750		750
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.75%
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.45%
First Mortgage Bonds, Stated Maturity 2043 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.60%
Long-term debt, gross	$ 375		375
First Mortgage Bonds, Stated Maturity 2044 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.75%
Long-term debt, gross	$ 675		675
First Mortgage Bonds, Stated Maturity 2045 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.30%
Long-term debt, gross	$ 600		600
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,050		1,050
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.00%
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.25%
First Mortgage Bonds, Stated Maturity 2047 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	3.95%
Long-term debt, gross	$ 850		850
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 5,025		5,025
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.50%
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.95%
First Mortgage Bonds, Stated Maturity 2052 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	5.25%	5.25%
Long-term debt, gross	$ 550		0
Recovery Bonds		$ 550
Recovery Bonds | Secured Debt
Debt [Line Items]
Long-term debt, gross	9,292		860
Less: current portion, net of unamortized discount and debt issuance costs	(168)		(18)
Recovery Bonds	1,800		860	$ 860
DWR Loan
Debt [Line Items]
Long-term debt, net	312		0
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	1,184		974
Long-term debt, net	$ 1,184		$ 974
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Debt, average interest rate			1.30%
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | SOFR
Debt [Line Items]
Debt, average interest rate	5.10%
2 Year Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Term Loan	$ 400		$ 0
18-Months Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Term Loan	$ 0		$ 1,441
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Stated interest rate			2.38%
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | SOFR
Debt [Line Items]
Stated interest rate	5.71%

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DEBT (Schedule of Contractual Repayment Schedule) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt [Line Items]
Total consolidated debt	$ 49,959
Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	1,825
SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 7,467
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.84%
Fixed rate obligations	$ 34,402
Variable interest rate as of December 31, 2022	5.54%
Variable rate obligations	$ 1,584
PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.13%
Fixed rate obligations	$ 2,000
Variable interest rate as of December 31, 2022	7.13%
Variable rate obligations	$ 2,681
2023
Debt [Line Items]
Total consolidated debt	2,271
2023 | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	38
2023 | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 130
2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	2.91%
Fixed rate obligations	$ 2,075
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
2023 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2022	7.13%
Variable rate obligations	$ 28
2024
Debt [Line Items]
Total consolidated debt	3,587
2024 | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	46
2024 | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 129
2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.40%
Fixed rate obligations	$ 1,800
Variable interest rate as of December 31, 2022	5.54%
Variable rate obligations	$ 1,584
2024 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2022	7.13%
Variable rate obligations	$ 28
2025
Debt [Line Items]
Total consolidated debt	4,733
2025 | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	48
2025 | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 135
2025 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.82%
Fixed rate obligations	$ 1,925
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
2025 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2022	7.13%
Variable rate obligations	$ 2,625
2026
Debt [Line Items]
Total consolidated debt	2,742
2026 | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	50
2026 | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 141
2026 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.10%
Fixed rate obligations	$ 2,551
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
2026 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
2027
Debt [Line Items]
Total consolidated debt	3,197
2027 | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	51
2027 | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 146
2027 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.22%
Fixed rate obligations	$ 3,000
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
2027 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
Thereafter
Debt [Line Items]
Total consolidated debt	33,429
Thereafter | Series 2022-A Recovery Bonds
Debt [Line Items]
Fixed rate obligations	1,592
Thereafter | SB 901 Securitization
Debt [Line Items]
Fixed rate obligations	$ 6,786
Thereafter | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	4.12%
Fixed rate obligations	$ 23,051
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0
Thereafter | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.13%
Fixed rate obligations	$ 2,000
Variable interest rate as of December 31, 2022	0.00%
Variable rate obligations	$ 0

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Narrative) (Details) - USD ($) $ in Millions			3 Months Ended	12 Months Ended
	Jul. 19, 2022	May 09, 2022	Jun. 30, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jul. 25, 2022	Jul. 20, 2022	May 16, 2022	May 10, 2022	Apr. 04, 2022	Feb. 28, 2022	Feb. 18, 2022	May 11, 2021	Apr. 23, 2021	Apr. 30, 2020
Debt [Line Items]
Initial shareholder contribution					$ 2,000
Regulatory assets					16,443	$ 9,207
Regulatory liabilities					17,630	11,999
SB 901 securitization charges, net					608	0	$ 0
SB 901 Securitization
Debt [Line Items]
Regulatory liabilities			$ 5,540		5,800	0
SB 901 Securitization
Debt [Line Items]
Regulatory assets			5,500		5,378	0
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Regulatory assets					16,443	9,207
Regulatory liabilities					17,630	11,999
SB 901 securitization charges, net					608	0	$ 0
SB 901 Securitization | Secured Debt
Debt [Line Items]
Initial shareholder contribution			2,000
Initial shareholder contribution, 2022					1,000
Initial shareholder contribution, contributed in 2024					1,000
Additional contributions funded by tax benefits					7,590
Contingent supplemental shareholder contribution					$ 775
Percent of surplus of shareholder assets					25.00%
Customer Harm Threshold, post-emergence transaction, stress test cost													$ 7,500
Debt instrument, face amount					$ 7,500				$ 3,900		$ 3,600
Amount contributed	$ 520	$ 480
SB 901 securitization charges, net					608
SB 901 Securitization | Secured Debt | Forecast
Debt [Line Items]
SB 901 securitization charges, net				$ 2,090
Floating Rate Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount										$ 500
1.75% Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount										$ 2,500
Interest rate										1.75%
First Mortgage Bonds Due 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount								$ 1,500
Interest rate								1.367%
364-Day 2022A Tranche Loans | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross												$ 500
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount														$ 1,000
Interest rate														3.25%
Long-term debt, gross					$ 1,800	$ 800
Nothern California Wild Fire
Debt [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized															$ 7,500	$ 7,500	$ 7,500
Loss contingency, costs incurred			$ 7,500

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Recovery Bonds) (Details) - USD ($) $ in Thousands	Nov. 30, 2022	Jul. 20, 2022	May 10, 2022
Series 2022-A Recovery Bonds
Debt [Line Items]
Amount	$ 983,000
Series 2022-A Recovery Bonds | Tranche One
Debt [Line Items]
Amount	$ 215,000
Interest rate	5.045%
Series 2022-A Recovery Bonds | Tranche Two
Debt [Line Items]
Amount	$ 200,000
Interest rate	5.256%
Series 2022-A Recovery Bonds | Tranche Three
Debt [Line Items]
Amount	$ 568,000
Interest rate	5.536%
Series 2022-A Recovery Bonds | Secured Debt | Tranche One
Debt [Line Items]
Amount			$ 540,000
Interest rate			3.594%
Series 2022-A Recovery Bonds | Secured Debt | Tranche Two
Debt [Line Items]
Amount			$ 540,000
Interest rate			4.263%
Series 2022-A Recovery Bonds | Secured Debt | Tranche Three
Debt [Line Items]
Amount			$ 360,000
Interest rate			4.377%
Series 2022-A Recovery Bonds | Secured Debt | Tranche Four
Debt [Line Items]
Amount			$ 1,260,000
Interest rate			4.451%
Series 2022-A Recovery Bonds | Secured Debt | Tranche Five
Debt [Line Items]
Amount			$ 900,000
Interest rate			4.674%
Series 2022-B Recovery Bonds | Secured Debt | Tranche One
Debt [Line Items]
Amount		$ 613,080
Interest rate		4.022%
Series 2022-B Recovery Bonds | Secured Debt | Tranche Two
Debt [Line Items]
Amount		$ 600,000
Interest rate		4.722%
Series 2022-B Recovery Bonds | Secured Debt | Tranche Three
Debt [Line Items]
Amount		$ 500,040
Interest rate		5.081%
Series 2022-B Recovery Bonds | Secured Debt | Tranche Four
Debt [Line Items]
Amount		$ 1,149,960
Interest rate		5.212%
Series 2022-B Recovery Bonds | Secured Debt | Tranche Five
Debt [Line Items]
Amount		$ 1,036,920
Interest rate		5.099%

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Financial Statement Impact) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt [Line Items]
Regulatory assets	$ 16,443	$ 9,207
Ending balance	16,443
Regulatory liability balance at inception	(11,999)
Ending balance	(17,630)
SB 901 Securitization Inception
Debt [Line Items]
Regulatory liability balance at inception	(5,540)
Amortization	308
Additions	(568)
Ending balance	(5,800)
SB 901 Securitization Inception
Debt [Line Items]
Regulatory assets	5,378	$ 5,500
Amortization	(122)
Ending balance	$ 5,378

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COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($)							12 Months Ended
	Feb. 16, 2023	Jan. 09, 2023	Dec. 20, 2022	Sep. 16, 2022	Jun. 17, 2022	May 28, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jul. 08, 2021	Apr. 30, 2021
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)							1,987,784,948	1,985,400,540
Treasury stock, shares at cost (in shares)							247,743,590	477,743,590
Shares outstanding (in shares)	2,466,208,388
Equity capital structure percentage							5200.00%
Equity capital structure, waiver period						5 years
Non-GAAP core earnings threshold							$ 6,200,000,000
Shares available for LTIP award (in shares)							53,350,101
Weighted average grant date fair value of granted shares (in dollars per share)							$ 11.40	$ 11.01	$ 9.25
Total fair value							$ 46,000,000	$ 19,000,000	$ 31,000,000
Total unrecognized compensation costs							$ 74,000,000
Remaining weighted average period							1 year 5 months 23 days
Pacific Gas & Electric Co (Utility)
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)							230,000,000
Pacific Gas & Electric Co (Utility)
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)							264,374,809	264,374,809
Shares outstanding (in shares)	264,374,809
Common stock dividends paid			$ 425,000,000	$ 425,000,000	$ 425,000,000		$ 1,275,000,000	$ 0	$ 0
Fire Victim Trust
Schedule of Capitalization, Equity [Line Items]
Number of shares exchanged (in shares)							230,000,000
Shares sold, tax impact							$ 870,000,000
Fire Victim Trust | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Number of shares exchanged (in shares)		60,000,000
Number of shares sold (in shares)	290,000,000
2014 LTIP, Amended
Schedule of Capitalization, Equity [Line Items]
Number of shares issued for LTIP, maximum (in shares)							91,000,000
Stock Options
Schedule of Capitalization, Equity [Line Items]
Granted (in shares)							0	0
Weighted-average period							11 months 8 days
Stock Options | 2014 LTIP
Schedule of Capitalization, Equity [Line Items]
Term of award							10 years
Award vesting period							3 years
Total unrecognized compensation costs							$ 0
Granted (in shares)							0
Restricted stock units
Schedule of Capitalization, Equity [Line Items]
Award vesting period							3 years
Tax detriment							$ 4,000,000
Performance shares
Schedule of Capitalization, Equity [Line Items]
Award vesting period							3 years
Industry performance period							3 years
Award grant date fair value recognition period							3 years
Performance shares granted (in dollars per share)							$ 13.44	$ 11.83	$ 9.62
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized							$ 43,000,000
PG&E Corporation | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding, adjusted (in shares)	1,800,721,208
PG&E Corporation | Equity Units
Schedule of Capitalization, Equity [Line Items]
Stock issued during period, shares, new issues (in shares)									16,000,000
PG&E Corporation | Minimum
Schedule of Capitalization, Equity [Line Items]
Percentage of equity security ownership with board of director approval							4.75%			4.75%
PG&E Corporation | Minimum | Revolving Credit Facility
Schedule of Capitalization, Equity [Line Items]
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance							150.00%
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared							100.00%
PG&E Corporation | Minimum | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Percentage of equity security ownership with board of director approval	3.46%
PG&E Corporation | Minimum | Common Stock
Schedule of Capitalization, Equity [Line Items]
Amount of shares, right to receive									138,000,000
PG&E Corporation | Maximum | Revolving Credit Facility
Schedule of Capitalization, Equity [Line Items]
Debt, ratio of total consolidated debt to consolidated capitalization							70.00%
PG&E Corporation | Maximum | Common Stock
Schedule of Capitalization, Equity [Line Items]
Amount of shares, right to receive									168,000,000
PG&E Corporation | At The Market Equity Distribution Program | Common Stock
Schedule of Capitalization, Equity [Line Items]
Sale of stock, number of shares issued in transaction, amount											$ 400,000,000

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COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 115	$ 56	$ 35
Total compensation expense (after-tax)	83	40	25
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	0	0	3
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	60	35	15
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 55	$ 21	$ 17

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COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Number of Stock Options
Granted (in shares)	0	0
2014 LTIP
Number of Stock Options
Outstanding, beginning of period (in shares)	2,195,834
Granted (in shares)	0
Exercised (in shares)	0
Forfeited or expired (in shares)	(43,702)
Outstanding, end of period (in shares)	2,152,132	2,195,834
Vested or expected to vest (in shares)	2,152,132
Exercisable (in shares)	2,152,132
Weighted Average Grant- Date Fair Value
Outstanding, beginning of period (in dollars per share)	$ 7.42
Forfeited or expired (in dollars per share)	10.23
Outstanding, end of period (in dollars per share)	7.36	$ 7.42
Vested or expected to vest (in dollars per share)	7.36
Exercisable (in dollars per share)	$ 7.36
Weighted Average Remaining Contractual Term
Outstanding	2 years 4 months 28 days
Expected to vest	2 years 4 months 28 days
Exercisable	2 years 4 months 28 days

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COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Number of Restricted Stock Units
Nonvested, beginning balance (in shares)	10,090,375
Granted (in shares)	5,850,945
Vested (in shares)	(4,175,008)
Forfeited (in shares)	(788,192)
Nonvested, ending balance (in shares)	10,978,120	10,090,375
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 11.00
Granted (in dollars per share)	11.40	$ 11.01	$ 9.25
Vested (in dollars per share)	10.96
Forfeited (in dollars per share)	11.18
Nonvested, ending balance (in dollars per share)	$ 11.21	$ 11.00

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COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Number of Restricted Stock Units
Nonvested , beginning balance (in shares)	8,567,009
Granted (in shares)	3,105,604
Vested (in shares)	0
Forfeited (in shares)	(650,559)
Nonvested, ending balance (in shares)	11,022,054	8,567,009
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 9.64
Granted (in dollars per share)	13.44	$ 11.83	$ 9.62
Vested (in dollars per share)	0
Forfeited (in dollars per share)	10.15
Nonvested, ending balance (in dollars per share)	$ 10.68	$ 9.64

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PREFERRED STOCK (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Dec. 15, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jan. 31, 2022
Preferred Stock [Line Items]
Cumulative and unpaid dividends					$ 59.1
Preferred stock dividend requirement	$ 3.5	$ 13.0
Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock dividend requirement		11.0
Preferred stock dividend requirement		$ 14.0	$ 14.0	$ 14.0
Pacific Gas & Electric Co (Utility) | Minimum
Preferred Stock [Line Items]
Redemption price (in dollars per share)		$ 25.75	$ 25.75
Pacific Gas & Electric Co (Utility) | Maximum
Preferred Stock [Line Items]
Redemption price (in dollars per share)		$ 27.25	$ 27.25
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock
Preferred Stock [Line Items]
Nonredeemable preferred stock outstanding		$ 145.0	$ 145.0
Preferred stock dividends per share, low range (in dollars per share)		$ 1.25
Preferred stock dividends per share, high range (in dollars per share)		$ 1.50
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate		5.00%	5.00%
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate		6.00%	6.00%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock
Preferred Stock [Line Items]
Redeemable preferred stock outstanding		$ 113.0	$ 113.0
Preferred stock dividends per share, low range (in dollars per share)		$ 1.09
Preferred stock dividends per share, high range (in dollars per share)		$ 1.25
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate		4.36%	4.36%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate		5.00%	5.00%
PG&E Corporation
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		400,000,000
Preferred stock, shares outstanding (in shares)		0
$25 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		75,000,000
Preferred stock, par value (in dollars per share)		$ 25
$100 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		10,000,000
Preferred stock, shares outstanding (in shares)		0
Preferred stock, par value (in dollars per share)		$ 100

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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, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Income (loss) available for common shareholders	$ 1,800	$ (102)	$ (1,318)
Weighted average common shares outstanding, basic (in shares)	1,987	1,985	1,257
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	8	0	0
Equity Units (in shares)	137	0	0
Weighted average common share outstanding, diluted (in shares)	2,132	1,985	1,257
Total earnings (loss) per common share, diluted (in dollars per share)	$ 0.84	$ (0.05)	$ (1.05)

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INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current:
Federal	$ (1)	$ 0	$ (26)
State	0	1	(34)
Deferred:
Federal	(943)	543	258
State	(389)	296	171
Tax credits	(5)	(4)	(7)
Income tax provision (benefit)	(1,338)	836	362
Pacific Gas & Electric Co (Utility)
Current:
Federal	(1)	0	(26)
State	0	0	(34)
Deferred:
Federal	(852)	588	290
State	(348)	316	185
Tax credits	(5)	(4)	(7)
Income tax provision (benefit)	$ (1,206)	$ 900	$ 408

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INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Pacific Gas & Electric Co (Utility)
Deferred income tax assets:
Tax carryforwards	$ 6,868	$ 5,425
Compensation	80	108
Greenhouse gas allowance	239	157
Wildfire-related claims	1,489	1,723
Operating lease liability	368	346
Transmission tower wireless licenses	254	266
Other	177	136
Total deferred income tax assets	9,475	8,161
Deferred income tax liabilities:
Property related basis differences	9,363	8,835
Regulatory balancing accounts	1,376	1,193
Debt financing costs	465	501
Operating lease right of use asset	368	346
Income tax regulatory asset	764	517
Other	230	178
Total deferred income tax liabilities	12,566	11,570
Total net deferred income tax liabilities	3,091	3,409
PG&E Corporation
Deferred income tax assets:
Tax carryforwards	7,156	5,628
Compensation	157	185
Greenhouse gas allowance	239	157
Wildfire-related claims	1,489	1,723
Operating lease liability	368	346
Transmission tower wireless licenses	254	266
Other	197	121
Total deferred income tax assets	9,860	8,426
Deferred income tax liabilities:
Property related basis differences	9,374	8,847
Regulatory balancing accounts	1,376	1,193
Debt financing costs	465	501
Operating lease right of use asset	368	346
Income tax regulatory asset	764	517
Other	245	199
Total deferred income tax liabilities	12,592	11,603
Total net deferred income tax liabilities	$ 2,732	$ 3,177

XML

INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pacific Gas & Electric Co (Utility)
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate	21.00%	21.00%	21.00%
State income tax (net of federal benefit)	(26.90%)	24.10%	19.10%
Effect of regulatory treatment of fixed asset differences	(49.20%)	(51.60%)	(44.90%)
Tax credits	(1.30%)	(1.20%)	(1.70%)
Fire Victim Trust	(0.640)	0.919	0.517
Bankruptcy and emergence	0.00%	0.00%	2.40%
Other, net	2.20%	2.60%	2.20%
Effective tax rate	(118.20%)	86.80%	49.80%
PG&E Corporation
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate	21.00%	21.00%	21.00%
State income tax (net of federal benefit)	(75.80%)	31.30%	(15.30%)
Effect of regulatory treatment of fixed asset differences	(123.80%)	(71.50%)	39.00%
Tax credits	3.20%	1.70%	(1.50%)
Fire Victim Trust	(1.609)	1.273	(0.449)
Bankruptcy and emergence	0.00%	0.00%	(37.60%)
Other, net	12.90%	5.30%	(2.10%)
Effective tax rate	(329.80%)	111.70%	(38.40%)

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INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pacific Gas & Electric Co (Utility)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	$ 498	$ 437	$ 420
Reductions for tax position taken during a prior year	(1)	(23)	(43)
Additions for tax position taken during the current year	73	85	60
Settlements	0	(1)	0
Balance, end of period	570	498	437
PG&E Corporation
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	498	437	420
Reductions for tax position taken during a prior year	(1)	(23)	(43)
Additions for tax position taken during the current year	73	85	60
Settlements	0	(1)	0
Balance, end of period	$ 570	$ 498	$ 437

XML

INCOME TAXES (Narrative) (Details) - USD ($) shares in Millions, $ in Millions			1 Months Ended	12 Months Ended
	Feb. 16, 2023	Jan. 09, 2023	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Investments, Owned, Federal Income Tax Note [Line Items]
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year				$ 31
Equity securities ownership, threshold				4.75%
Income tax provision (benefit)				$ (1,338)	$ 836	$ 362
Fire Victim Trust
Investments, Owned, Federal Income Tax Note [Line Items]
Shares sold, tax impact				$ 870
Number of shares exchanged (in shares)				230
Fire Victim Trust | Subsequent Event
Investments, Owned, Federal Income Tax Note [Line Items]
Number of shares sold (in shares)	290
Number of shares exchanged (in shares)		60
Income tax provision (benefit)			$ (256)

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INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	$ 152
Federal | Pre-2018
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	3,447
Federal | Post-2017
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	23,170
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	25,169
Tax credit carryforward	$ 126

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DERIVATIVES (Narrative) (Details)	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Regulatory assets	Regulatory assets

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DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)	Dec. 31, 2022 MWh MMBTU	Dec. 31, 2021 MWh MMBTU
Forwards, Futures and Swaps | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume	171,212,813	173,361,635
Forwards, Futures and Swaps | Electricity (MWh)
Derivative [Line Items]
Contract Volume | MWh	10,814,728	10,283,639
Options | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume	27,785,000	14,420,000
Options | Electricity (MWh)
Derivative [Line Items]
Contract Volume	215,600	288,000
Congestion revenue rights | Electricity (MWh)
Derivative [Line Items]
Contract Volume | MWh	205,743,505	239,857,610

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DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Contract - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivatives And Hedging Activities [Line Items]
Netting	$ 715	$ (42)
Netting	0	0
Cash Collateral	553	170
Total Derivative Balance	1,268	128
Current assets – other
Derivatives And Hedging Activities [Line Items]
Netting	824	58
Netting	(170)	(9)
Cash Collateral	537	152
Total Derivative Balance	1,191	201
Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Netting	306	169
Netting	0	0
Cash Collateral	0	0
Total Derivative Balance	306	169
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(238)	(53)
Netting	170	9
Cash Collateral	16	18
Total Derivative Balance	(52)	(26)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(177)	(216)
Netting	0	0
Cash Collateral	0	0
Total Derivative Balance	$ (177)	$ (216)

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FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Assets:
Short-term investments		$ 289
Price risk management instruments, netting	$ 367	143
Price risk management instruments, assets	1,497	370
TOTAL ASSETS	7,127	5,558
Liabilities:
Price risk management instruments, netting	(186)	(27)
TOTAL LIABILITIES	229	242
Amount primarily related to deferred taxes on appreciation of investment value	575	783
Short-term investments
Assets:
Short-term investments	658
Fixed-income securities
Assets:
Short-term investments	49
Nuclear decommissioning trusts
Assets:
Short-term investments	117	22
Global equity securities	1,845	2,504
Fixed-income securities	1,885	2,024
TOTAL ASSETS	3,872	4,581
Customer credit trust
Assets:
Short-term investments	19
Global equity securities	218
Fixed-income securities	508
TOTAL ASSETS	745
Rabbi trusts
Assets:
Short-term investments	25
Global equity securities	5
Fixed-income securities	69	104
Life insurance contracts	64	76
TOTAL ASSETS	163	180
Long-term disability trust
Assets:
Short-term investments	10	6
TOTAL ASSETS	143	138
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	40	6
Price risk management instruments, assets	566	229
Liabilities:
Price risk management instruments, netting	(20)	(24)
Price risk management instruments, liabilities	223	235
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	327	137
Price risk management instruments, assets	931	141
Liabilities:
Price risk management instruments, netting	(166)	(3)
Price risk management instruments, liabilities	6	7
Level 1
Assets:
Short-term investments		289
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	4,207	3,979
Liabilities:
TOTAL LIABILITIES	0	0
Level 1 | Short-term investments
Assets:
Short-term investments	658
Level 1 | Fixed-income securities
Assets:
Short-term investments	0
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	117	22
Global equity securities	1,845	2,504
Fixed-income securities	1,094	1,158
TOTAL ASSETS	3,056	3,684
Level 1 | Customer credit trust
Assets:
Short-term investments	19
Global equity securities	218
Fixed-income securities	216
TOTAL ASSETS	453
Level 1 | Rabbi trusts
Assets:
Short-term investments	25
Global equity securities	5
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	30	0
Level 1 | Long-term disability trust
Assets:
Short-term investments	10	6
TOTAL ASSETS	10	6
Level 1 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 1 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 2
Assets:
Short-term investments		0
Price risk management instruments, gross subject to netting	698	13
TOTAL ASSETS	1,963	1,059
Liabilities:
TOTAL LIABILITIES	182	21
Level 2 | Short-term investments
Assets:
Short-term investments	0
Level 2 | Fixed-income securities
Assets:
Short-term investments	49
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	791	866
TOTAL ASSETS	791	866
Level 2 | Customer credit trust
Assets:
Short-term investments	0
Global equity securities	0
Fixed-income securities	292
TOTAL ASSETS	292
Level 2 | Rabbi trusts
Assets:
Short-term investments	0
Global equity securities	0
Fixed-income securities	69	104
Life insurance contracts	64	76
TOTAL ASSETS	133	180
Level 2 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 2 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	94	9
Liabilities:
Price risk management instruments, gross subject to netting	10	11
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	604	4
Liabilities:
Price risk management instruments, gross subject to netting	172	10
Level 3
Assets:
Short-term investments		0
Price risk management instruments, gross subject to netting	432	214
TOTAL ASSETS	432	214
Liabilities:
TOTAL LIABILITIES	233	248
Level 3 | Short-term investments
Assets:
Short-term investments	0
Level 3 | Fixed-income securities
Assets:
Short-term investments	0
Level 3 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	0	0
TOTAL ASSETS	0	0
Level 3 | Customer credit trust
Assets:
Short-term investments	0
Global equity securities	0
Fixed-income securities	0
TOTAL ASSETS	0
Level 3 | Rabbi trusts
Assets:
Short-term investments	0
Global equity securities	0
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 3 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 3 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	432	214
Liabilities:
Price risk management instruments, gross subject to netting	233	248
Level 3 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Fair Value Measured at Net Asset Value Per Share | Nuclear decommissioning trusts
Assets:
Assets measured at NAV	25	31
Fair Value Measured at Net Asset Value Per Share | Long-term disability trust
Assets:
Assets measured at NAV	$ 133	$ 132

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FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 USD ($) $ / shares
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 1,497	$ 370
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	305	188
Liabilities | $	138	93
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	127	26
Liabilities | $	$ 95	$ 155
CRR auction prices | Market approach | Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	(145.09)	(40.77)
CRR auction prices | Market approach | Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	2,724.93	2,265.94
CRR auction prices | Market approach | Congestion revenue rights | Weighted average price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	0.89	0.40
Forward prices | Discounted cash flow | Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	(6.39)	(7.97)
Forward prices | Discounted cash flow | Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	286.75	256.20
Forward prices | Discounted cash flow | Power purchase agreements | Weighted average price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	78.14	47.17

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FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Asset (Liability) balance, beginning of period	$ (34)	$ (72)
Included in regulatory assets and liabilities or balancing accounts	233	38
Asset (Liability) balance, end of period	$ 199	$ (34)

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FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Carrying Amount
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 4,355	$ 4,619
Carrying Amount | Pacific Gas & Electric Co (Utility)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	32,847	31,816
Level 2 | Fair Value
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	4,490	4,796
Level 2 | Fair Value | Pacific Gas & Electric Co (Utility)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 27,666	$ 35,803

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FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Securities, Available-for-sale [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$ 575	$ 783
Nuclear decommissioning trusts
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	2,521	2,439
Total Unrealized Gains	1,478	2,164
Total Unrealized Losses	(127)	(22)
Total Fair Value	3,872	4,581
Nuclear decommissioning trusts | Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	117	22
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	117	22
Nuclear decommissioning trusts | Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	413	479
Total Unrealized Gains	1,468	2,066
Total Unrealized Losses	(11)	(10)
Total Fair Value	1,870	2,535
Nuclear decommissioning trusts | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,991	1,938
Total Unrealized Gains	10	98
Total Unrealized Losses	(116)	(12)
Total Fair Value	1,885	$ 2,024
Customer credit trust
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	754
Total Unrealized Gains	13
Total Unrealized Losses	(22)
Total Fair Value	745
Customer credit trust | Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	19
Total Unrealized Gains	0
Total Unrealized Losses	0
Total Fair Value	19
Customer credit trust | Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	219
Total Unrealized Gains	13
Total Unrealized Losses	(14)
Total Fair Value	218
Customer credit trust | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	516
Total Unrealized Gains	0
Total Unrealized Losses	(8)
Total Fair Value	$ 508

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FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Nuclear decommissioning trusts
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 3,872	$ 4,581
Nuclear decommissioning trusts | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	42
1–5 years	624
5–10 years	400
More than 10 years	819
Total maturities of fixed-income securities	1,885	$ 2,024
Customer credit trust
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	745
Customer credit trust | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	79
1–5 years	123
5–10 years	120
More than 10 years	186
Total maturities of fixed-income securities	$ 508

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FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 3,316	$ 1,678	$ 1,518
Impairment loss	6
Nuclear decommissioning trusts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	3,316	1,678	1,518
Gross realized gains on securities	2	286	159
Gross realized losses on securities	(3)	$ (19)	$ (41)
Customer credit trust
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	250
Gross realized gains on securities	10
Gross realized losses on securities	$ (41)

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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, 2022	Dec. 31, 2021	Dec. 31, 2020
Funded Status:
Noncurrent liability	$ (231)	$ (860)
Pension Plan
Change in plan assets:
Fair value of plan assets at beginning of year	21,895	20,759
Actual return on plan assets	(4,916)	1,693
Company contributions	339	335
Benefits and expenses paid	(949)	(892)
Fair value of plan assets at end of year	16,369	21,895	$ 20,759
Change in benefit obligation:
Benefit obligation at beginning of year	22,759	23,172
Service cost for benefits earned	575	587	530
Interest cost	692	645	713
Actuarial gain	(6,471)	(752)
Plan amendments	0	0
Benefits and expenses paid	(947)	(893)
Benefit obligation at end of year	16,608	22,759	23,172
Funded Status:
Current liability	(8)	(9)
Noncurrent liability	(231)	(856)
Net (liability) asset at end of year	(239)	(865)
Accumulated benefit obligation	15,400	20,400
PBOP Plans
Change in plan assets:
Fair value of plan assets at beginning of year	3,102	2,995
Actual return on plan assets	(693)	193
Company contributions	26	10
Plan participant contribution	81	80
Benefits and expenses paid	(180)	(176)
Fair value of plan assets at end of year	2,336	3,102	2,995
Change in benefit obligation:
Benefit obligation at beginning of year	1,766	1,876
Service cost for benefits earned	62	63	61
Interest cost	53	51	63
Actuarial gain	(486)	(152)
Benefits and expenses paid	(162)	(156)
Federal subsidy on benefits paid	3	4
Plan participant contributions	81	80
VSP related termination benefits	22	0
Benefit obligation at end of year	1,339	1,766	$ 1,876
Funded Status:
Noncurrent asset	997	1,340
Noncurrent liability	0	(4)
Net (liability) asset at end of year	997	1,336
PBOP Plans | Postretirement Life Insurance Plan
Change in plan assets:
Fair value of plan assets at beginning of year	359
Fair value of plan assets at end of year	266	359
Change in benefit obligation:
Benefit obligation at beginning of year	363
Benefit obligation at end of year	$ 259	$ 363

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EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 575	$ 587	$ 530
Interest cost	692	645	713
Expected return on plan assets	(1,189)	(1,046)	(1,044)
Amortization of prior service cost	(4)	(6)	(6)
Amortization of net actuarial loss	2	6	3
Net periodic benefit cost	76	186	196
Less: transfer to regulatory account	254	147	136
Total expense recognized	330	333	332
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	62	63	61
Interest cost	53	51	63
Expected return on plan assets	(130)	(137)	(138)
Amortization of prior service cost	7	14	14
Amortization of net actuarial loss	(40)	(33)	(21)
Special termination benefits	22	0	0
Net periodic benefit cost	$ (26)	$ (42)	$ (21)

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EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.80%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.54%	3.03%	2.77%
Rate of future compensation increases	3.80%	3.80%	3.80%
Expected return on plan assets	6.10%	5.50%	5.10%
Interest crediting rate for cash balance plan	4.19%	1.95%	1.95%
PBOP Plans | Minimum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.50%	2.97%	2.67%
Expected return on plan assets	3.70%	3.30%	3.10%
PBOP Plans | Maximum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.54%	3.04%	2.80%
Expected return on plan assets	7.30%	6.40%	6.10%

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EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) noncallable_bond	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Assumed health care cost trend rate	6.50%
Ultimate trend rate	4.50%
Assumed return	6.10%
10 year actual rate of return	5.80%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond	848
Total fair value of trust other net liabilities	$ 11	$ 175
Retirement savings plan expense	$ 144	$ 133	$ 119
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
10 year actual rate of return	6.10%	5.50%	5.10%
Company contributions	$ 339	$ 335
Expected employer contribution next year	327
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Company contributions	$ 26	$ 10

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EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		30.00%	30.00%
Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		2.00%	2.00%
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		8.00%	8.00%
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		60.00%	60.00%
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		26.00%	36.00%
PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		1.00%	1.00%
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		3.00%	5.00%
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		70.00%	58.00%
Forecast | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Forecast | Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	26.00%
Forecast | Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	1.00%
Forecast | Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	8.00%
Forecast | Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	65.00%
Forecast | PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Forecast | PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	28.00%
Forecast | PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	1.00%
Forecast | PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	3.00%
Forecast | PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	68.00%

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EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	$ 18,716	$ 25,172
Level 3
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	8	27	$ 12
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	16,369	22,054
Assets measured at NAV	16,369	21,895	20,759
Pension Plan | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	587	807
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,430	2,498
Pension Plan | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	1
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	426	632
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8,040	10,144
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	4,263	5,987
Pension Plan | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	461	552
Pension Plan | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,430	2,074
Pension Plan | Level 1 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	426	632
Pension Plan | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,946	2,729
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	6,212	8,068
Pension Plan | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	126	255
Pension Plan | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	424
Pension Plan | Level 2 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	1
Pension Plan | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	6,086	7,388
Pension Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8	27
Pension Plan | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8	27
Pension Plan | Fair Value Measured at Net Asset Value Per Share
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	5,886	7,972
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,347	3,118
Assets measured at NAV	2,336	3,102	$ 2,995
PBOP Plans | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	26	31
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	83	105
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	29	34
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,109	1,652
PBOP Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	544	946
PBOP Plans | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	26	31
PBOP Plans | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	83	105
PBOP Plans | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	29	34
PBOP Plans | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	406	776
PBOP Plans | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	702	875
PBOP Plans | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	702	875
PBOP Plans | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	1
PBOP Plans | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	1
PBOP Plans | Fair Value Measured at Net Asset Value Per Share
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	$ 1,100	$ 1,296

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EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets at beginning of year	$ 27	$ 12
Actual return on plan assets:
Relating to assets still held at the reporting date	1	6
Relating to assets sold during the period	0	(7)
Purchases, issuances, sales, and settlements:
Purchases	6	22
Settlements	(26)	(6)
Fair value of plan assets at end of year	$ 8	$ 27

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EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2023	$ 907
2024	996
2025	1,028
2026	1,057
2027	1,082
Thereafter in the succeeding five years	5,702
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
2023	97
2024	98
2025	100
2026	94
2027	94
Thereafter in the succeeding five years	475
Federal Subsidy
Defined Benefit Plan Disclosure [Line Items]
2023	(4)
2024	(4)
2025	(4)
2026	(4)
2027	(4)
Thereafter in the succeeding five years	$ (4)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Administrative services provided to PG&E Corporation
Related Party Transaction [Line Items]
Utility revenues from	$ 3	$ 3	$ 3
Administrative services received from PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	104	82	108
Utility employee benefit due to PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	$ 85	$ 39	$ 34

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - USD ($) $ in Millions	Aug. 11, 2021	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Intercompany note to PG&E Corporation	$ 145
Pacific Gas & Electric Co (Utility)
Related Party Transaction [Line Items]
Current receivables		$ 33	$ 173
Current payables		$ 46	$ 19

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WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2020 Zogg Fire, 2021 Dixie Fire and 2022 Mosquito Fire) (Details) $ in Thousands, numberOfPeople in Millions							3 Months Ended	12 Months Ended
	Feb. 21, 2023 USD ($)	Oct. 25, 2022 USD ($)	Mar. 18, 2022 USD ($)	Jan. 05, 2022 USD ($)	Oct. 29, 2021 USD ($) a	Nov. 04, 2019 numberOfPeople	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Feb. 16, 2023 plaintiff complaint notice numberOfPlaintiff numberOfClaimHolder	Feb. 03, 2023 notice	Jan. 17, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 06, 2022 a injury numberOfFatality structure	Aug. 31, 2022 USD ($)	Jul. 14, 2022 transmissionLine	Jun. 09, 2022 notice	Apr. 28, 2022 USD ($)	Apr. 11, 2022 USD ($) position	Apr. 08, 2022 USD ($) position	Jan. 28, 2022 notice	Jan. 27, 2022 notice	Nov. 18, 2021 notice	Sep. 30, 2021 USD ($)	Sep. 24, 2021 misdemeanor felony	Jul. 13, 2021 a structure injury	Apr. 06, 2021 misdemeanor felony	Sep. 27, 2020 a injury fatality structure	Oct. 23, 2019 a structure numberOfFatality injury
Loss Contingencies [Line Items]
Amount expected to pay								$ 477,000	$ 517,000	$ 413,000
Accrued insurance recoveries								45,000
2019 Kincade fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a																														77,758
Number of fatalities (fatality) | numberOfFatality																														0
Number of injuries | injury																														4
Number of structures destroyed (structure) | structure																														374
Number of structures damaged (structure) | structure																														60
Number of people part of mandatory evacuation order | numberOfPeople						0.2
Number of felonies (felony) | notice																						5	2
Number of misdemeanors dropped (misdemeanor) | notice																						6
Stipulation costs payable																					$ 20,250
Number of new positions headquartered (position) | position																					80
Stipulation costs paid								5,450
Number of transmission lines | transmissionLine																	70
Payments								344,000
Fire fighting costs recovery requested				$ 90,000
Potential loss contingency								1,025,000	800,000
Accrued Losses								225,000
Insurance receivable								430,000
Accrued insurance recoveries								0
2020 Zogg fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a																													56,338
Number of fatalities (fatality) | fatality																													4
Number of injuries | injury																													1
Number of structures destroyed (structure) | structure																													204
Number of structures damaged (structure) | structure																													27
Payments								204,000
Potential loss contingency								400,000	375,000
Accrued Losses								25,000
Insurance receivable								370,000
Number of demurrer filed (count) | notice																								10
Number of criminal complaints (count) | notice																								31
Number of criminal complaints dismissed (count) | notice																		20
Penalty recommended		$ 155,000
Litigation liability, payment accrual								10,000
Fire suppression and other costs			$ 34,500
Potential loss contingency, additional								25,000
Liability insurance coverage								611,000
Initial self-insured retention per occurrence								60,000
Legal fees								30,000
Accrued insurance recoveries								33,000
Zogg Complaint, 2020
Loss Contingencies [Line Items]
Number of felonies (felony) | felony																										11
Number of misdemeanors (misdemeanor) | misdemeanor																										20
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage																$ 600,000			$ 340,000
Initial self-insured retention per occurrence								60,000
2021 Dixie fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a																											963,309
Number of structures destroyed (structure) | structure																											1,311
Number of structures damaged (structure) | structure																											94
Stipulation costs payable																				$ 34,750
Number of new positions headquartered (position) | position																				80
Loss contingency liability								1,175,000
Loss contingency, costs incurred					$ 650,000
Payments								44,000
Potential loss contingency									1,150,000
Accrued Losses								25,000
Insurance receivable								530,000
Liability insurance coverage								900,000
Number of residential structures destroyed (structure) | structure																											763
Number of multi-family residential structures destroyed (structure) | structure																											12
Number of commercial residential structures destroyed (structure) | structure																											8
Number of commercial non-residential structures destroyed (structure) | structure																											148
Number of detached structures destroyed (structure) | structure																											466
Number of first responder injuries (injury) | injury																											4
Probable of recovery								1,208,000
Accrued insurance recoveries								(33,000)
Dixie Stipulation
Loss Contingencies [Line Items]
Payments								30,750
2022 Mosquito fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a															76,788
Number of fatalities (fatality) | numberOfFatality															0
Number of injuries | injury															0
Number of structures destroyed (structure) | structure															78
Number of structures damaged (structure) | structure															13
Loss contingency liability														$ 100,000
Liability insurance coverage								940,000
Probable of recovery								105,000
Percentage of fire contained															100.00%
Accrued insurance recoveries								45,000
Subsequent Event
Loss Contingencies [Line Items]
Settlement amount proposed													$ 24,000
Subsequent Event | 2019 Kincade fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint											113
Number of plaintiffs represented by complaints | plaintiff											2,720
Subsequent Event | 2020 Zogg fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint											29
Number of plaintiffs represented by complaints | numberOfPlaintiff											523
Number of criminal complaints (count) | notice												11
Costs unable to recover	$ 140,000
Subsequent Event | 2021 Dixie fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | numberOfClaimHolder											81
Number of plaintiffs represented by complaints | numberOfClaimHolder											2,094
Subsequent Event | 2022 Mosquito fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint											6
Number of plaintiffs represented by complaints | notice											236
FERC TO rates | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery								115,000
FERC TO rates | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery								10,000
WEMA | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery								388,000
Increase in regulatory asset								41,000
WEMA | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery								50,000
National Park | 2021 Dixie fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a					70,000
National Forrest | 2021 Dixie fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a					685,000
California General Fund | Subsequent Event | 2020 Zogg fire
Loss Contingencies [Line Items]
Amount expected to pay	$ 10,000
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Amount expected to pay								477,000	$ 517,000	$ 413,000
Pacific Gas & Electric Co (Utility) | 2019 Kincade fire
Loss Contingencies [Line Items]
Loss contingency liability																									$ 40,000
Loss contingency, costs incurred							$ 85,000	85,000
Pacific Gas & Electric Co (Utility) | Sonoma Contry District Attorney | 2019 Kincade fire
Loss Contingencies [Line Items]
Number of felonies (felony) | felony																												5
Number of misdemeanors (misdemeanor) | misdemeanor																												28
Pacific Gas & Electric Co (Utility) | California General Fund | 2019 Kincade fire
Loss Contingencies [Line Items]
Payments								$ 20,000

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WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
2019 Kincade fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	$ 769
Accrued Losses	225
Payments	(344)
Loss accrual, ending balance	650
2020 Zogg fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	211
Accrued Losses	25
Payments	(204)
Loss accrual, ending balance	32
2021 Dixie fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	1,150
Accrued Losses	25
Payments	(44)
Loss accrual, ending balance	$ 1,131

XML

WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	$ 105
2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	1,208
Insurance | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	45
Insurance | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	530
WEMA | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	50
WEMA | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	388
Wildfire Fund | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	0
Wildfire Fund | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	175
FERC TO rates | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	10
FERC TO rates | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	$ 115

XML

WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 28, 2022	Aug. 01, 2023	Apr. 01, 2023	Dec. 31, 2022	Aug. 31, 2022
Loss Contingencies [Line Items]
Insurance premium costs, recovery, coverage amount				$ 1,400
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage	$ 340				$ 600
Initial self-insured retention per occurrence				60
Insurance Coverage for Wildfire Events | Forecast
Loss Contingencies [Line Items]
Costs for insurance coverage		$ 516	$ 263
Insurance Coverage For Non-Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	725
Costs for insurance coverage	$ 154
Initial self-insured retention per occurrence				10
Prepaid insurance				$ 424

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WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	$ 1,247
Accrued insurance recoveries	45
Reimbursements	(498)
Insurance Receivable, Ending Balance	794
Resolved claims	418
Other Receivables
Insurance Receivable [Roll Forward]
Resolved claims	13
2022 Mosquito fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	0
Accrued insurance recoveries	45
Reimbursements	0
Insurance Receivable, Ending Balance	45
2021 Dixie fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	563
Accrued insurance recoveries	(33)
Reimbursements	0
Insurance Receivable, Ending Balance	530
Insurance receivable	530
2020 Zogg fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	270
Accrued insurance recoveries	33
Reimbursements	(185)
Insurance Receivable, Ending Balance	118
Insurance receivable	370
2019 Kincade fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	414
Accrued insurance recoveries	0
Reimbursements	(313)
Insurance Receivable, Ending Balance	101
Insurance receivable	$ 430

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WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	$ 1,208
2021 Dixie fire | FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	115
2021 Dixie fire | WEMA
Loss Contingencies [Line Items]
Probable of recovery	388
2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	105
2022 Mosquito fire | FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	10
2022 Mosquito fire | WEMA
Loss Contingencies [Line Items]
Probable of recovery	$ 50

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WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions		12 Months Ended
	Aug. 23, 2019	Dec. 31, 2022
Loss Contingencies [Line Items]
Disallowance cap, transmission and distribution 2022 equity rate base		$ 3,000
Initial safety certification, documentation provided, period	90 days
Initial safety certification, period	12 months
Expected capitalization, proceeds of bond		10,500
Expected capitalization, initial contribution		7,500
Expected capitalization, annual contribution		300
2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery		1,208
2021 Dixie fire | Wildfire Fund
Loss Contingencies [Line Items]
Probable of recovery		$ 175

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jul. 26, 2022
Loss Contingencies [Line Items]
Net Income (Loss)	$ (1,814)	$ 88	$ 1,304
Wildfire-Related Class Action
Loss Contingencies [Line Items]
Loss contingency liability	300
Net Income (Loss)	145
Insurance Coverage Claims
Loss Contingencies [Line Items]
Insurance receivable	$ 272
Breach of Fiduciary Duties
Loss Contingencies [Line Items]
Settlement amount proposed				$ 117

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties $ in Millions	Jul. 26, 2022 USD ($)	Feb. 24, 2021 claim	Nov. 20, 2017 lawsuit
Loss Contingencies [Line Items]
Number of causes of action (causes) | claim		2
Settlement amount proposed | $	$ 117
Derivative Lawsuits Filed in the San Francisco County Superior Court
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit			2

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation and Debt Claims) (Details) - Wildfire-Related Class Action $ in Millions	Dec. 31, 2022 USD ($)	Feb. 22, 2019 notice	Jun. 30, 2018 lawsuit
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit			2
Number of public offerings of notes with complaints against underwriters (offering) | notice		4
Loss contingency liability | $	$ 300
Percentage of common stock owned, Fire Victim Trust if common issues additional shares	22.19%

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WILDFIRE-RELATED CONTINGENCIES (Indemnification Obligations and D&O Insurance Coverage (Details) $ in Millions	Dec. 31, 2022 USD ($)
Insurance Coverage Claims
Loss Contingencies [Line Items]
Insurance receivable	$ 272

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WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co (Utility) - Complaints Brought By Butte County District Attorney - Loss from Wildfires	Mar. 17, 2020 count
Loss Contingencies [Line Items]
Number of guilty involuntary manslaughter pleas	84
Number of count related to unlawfully causing a fire (count)	1

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OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details) - USD ($) $ in Millions			61 Months Ended
	Mar. 17, 2022	Sep. 21, 2018	Mar. 31, 2022	Dec. 31, 2022
Transmission Owner Rate Case Revenue
Loss Contingencies [Line Items]
Regulatory liabilities				$ 416.0
Regulatory assets				$ 258.0
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Increase in regulatory liabilities			$ 62.5
Pacific Gas & Electric Co (Utility) | Electric
Loss Contingencies [Line Items]
Requested revenue rate		98.85%
Requested return on equity rate	9.26%
Requested return on equity rate, incentive component	0.50%
Actual return on equity rate	9.76%

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OTHER CONTINGENCIES AND COMMITMENTS - 2022 Cost of Capital Application (Details)	Dec. 31, 2022	Sep. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Annual cost of capital adjustment, indicator	4.50%
Annual cost of capital adjustment, basis point maximum	100
Proposed cost of long-term debt	4.14%
Proposed return on preferred stock	5.52%
Proposed return on equity	11.00%
Annual cost of capital adjustment, indicator, basis point		117

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OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Accrued legal liabilities	$ 69	$ 77

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OTHER CONTINGENCIES AND COMMITMENTS (PSPS Class Action) (Details) $ in Billions	Dec. 19, 2019 USD ($)
PSPS Class Action | Pending Litigation | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Loss contingency, damages sought	$ 2.5

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]
Topock natural gas compressor station	$ 284	$ 299
Hinkley natural gas compressor station	110	123
Former manufactured gas plant sites owned by the Utility or third parties	750	667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	112	104
Fossil fuel-fired generation facilities and sites	26	70
Total environmental remediation liability	$ 1,282	$ 1,263

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OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 1,050
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 240
Topock Site | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 126
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 511
Former Manufactured Gas Plant | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 51
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 50

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OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Purchase Commitments) (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Maximum total payment incurred per event under the loss sharing program	$ 450,000,000
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Insurance coverage, loss	400,000,000
Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	50,000,000
Amount of liability insurance for Humboldt Bay Unit 3	53,000,000
Diablo Canyon
Long-term Purchase Commitment [Line Items]
Maximum public liability per nuclear incident under Price-Anderson Act	13,700,000,000
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	450,000,000
Maximum annual payment incurred per event under the loss sharing program	275,000,000
Maximum annual payment incurred per event under the loss sharing program	$ 41,000,000
Period for inflation adjustment	5 years
Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	$ 3,200,000,000
Nuclear Incident | Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of indemnification from the nuclear regulatory commission for public liability arising from nuclear incidents	500,000,000
Non-Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,500,000,000
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Full insurance policy limit	200,000,000
Potential premium obligation	4,000,000
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation	$ 41,000,000

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Long-term Purchase Commitment [Line Items]
2023	$ 4,416
2024	2,697
2025	2,956
2026	2,793
2027	2,558
Thereafter	19,385
Total purchase commitments	34,805
Renewable Energy
Long-term Purchase Commitment [Line Items]
2023	2,081
2024	2,052
2025	2,040
2026	1,980
2027	1,919
Thereafter	17,807
Total purchase commitments	27,879
Conventional Energy
Long-term Purchase Commitment [Line Items]
2023	482
2024	378
2025	715
2026	663
2027	579
Thereafter	1,565
Total purchase commitments	4,382
Other
Long-term Purchase Commitment [Line Items]
2023	60
2024	61
2025	61
2026	21
2027	7
Thereafter	13
Total purchase commitments	223
Natural Gas
Long-term Purchase Commitment [Line Items]
2023	1,746
2024	195
2025	140
2026	129
2027	53
Thereafter	0
Total purchase commitments	2,263
Nuclear Fuel
Long-term Purchase Commitment [Line Items]
2023	47
2024	11
2025	0
2026	0
2027	0
Thereafter	0
Total purchase commitments	$ 58

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OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Power Purchases and Electric Capacity
Third-Party Power Purchase Agreements [Line Items]
Costs incurred for power purchases and electric capacity	$ 2,800	$ 3,000	$ 2,900
Nuclear Fuel
Third-Party Power Purchase Agreements [Line Items]
Payments for nuclear fuel	44	79	111
Gas Contracts
Third-Party Power Purchase Agreements [Line Items]
Cost of goods	$ 2,400	$ 1,200	$ 800

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2023	$ 88
2024	85
2025	83
2026	81
2027	80
Thereafter	3,518
Total minimum lease payments	$ 3,935

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OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Leased Assets [Line Items]
Payments for other commitments	$ 63	$ 50	$ 45
SB 901 Securitization | Secured Debt
Operating Leased Assets [Line Items]
Initial shareholder contribution, contributed in 2024	$ 1,000
Minimum
Operating Leased Assets [Line Items]
Extension option for operating leases	1 year
Maximum
Operating Leased Assets [Line Items]
Extension option for operating leases	5 years

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating expenses	$ (19,843)	$ (18,759)	$ (16,714)
Interest income	162	20	39
Interest expense	(1,917)	(1,601)	(1,260)
Other income, net	394	457	483
Reorganization items, net	0	(11)	(1,959)
Income tax provision (benefit)	(1,338)	836	362
Income (Loss) Attributable to Common Shareholders	1,800	(102)	(1,318)
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	21	7	(17)
Total other comprehensive income (loss)	$ 15	$ 7	$ (17)
Weighted Average Common Shares Outstanding, Basic (in shares)	1,987,000,000	1,985,000,000	1,257,000,000
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,132,000,000	1,985,000,000	1,257,000,000
Net earnings (loss) per common share, basic (in dollars per share)	$ 0.91	$ (0.05)	$ (1.05)
Net earnings (loss) per common share, diluted (in dollars per share)	$ 0.84	$ (0.05)	$ (1.05)
Pension and other postretirement benefit plans obligations, tax	$ 8	$ 3	$ 7
Treasury stock, shares at cost (in shares)	247,743,590	477,743,590
PG&E Corporation
Operating expenses	$ (193)	$ (124)	(103)
Interest income	3	0	0
Interest expense	(261)	(230)	(149)
Other income, net	(201)	(54)	13
Reorganization items, net	0	1	(1,649)
Equity in earnings of subsidiaries	2,154	137	411
Income (loss) before income taxes	1,611	(152)	(1,350)
Income tax provision (benefit)	(132)	(64)	(46)
Income (Loss) Attributable to Common Shareholders	1,743	(88)	(1,304)
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	21	7	(17)
Total other comprehensive income (loss)	21	7	(17)
Comprehensive Income (Loss)	$ 1,764	$ (81)	$ (1,321)
Weighted Average Common Shares Outstanding, Basic (in shares)	2,235,000,000	2,463,000,000	1,257,000,000
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,380,000,000	2,463,000,000	1,257,000,000
Net earnings (loss) per common share, basic (in dollars per share)	$ 0.78	$ (0.05)	$ (1.05)
Net earnings (loss) per common share, diluted (in dollars per share)	$ 0.73	$ (0.05)	$ (1.05)
Pension and other postretirement benefit plans obligations, tax	$ 8	$ 3	$ 7
PG&E Corporation | Administrative service revenue
Administrative service revenue	$ 109	$ 118	$ 127

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 734	$ 291	$ 484
Other	1,433	882
Total current assets	12,815	11,077
Noncurrent Assets
Equipment	107,154	98,960
Accumulated depreciation	(30,946)	(29,134)
Net property, plant, and equipment	76,208	69,826
TOTAL ASSETS	118,644	103,327
Current Liabilities
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	2,268	4,481
Other current liabilities	3,372	2,436
Total current liabilities	15,788	17,427
Noncurrent Liabilities
Long-term debt	47,742	38,225
Other	4,291	4,308
Total noncurrent liabilities	79,781	64,677
Common Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates	32,887	35,129
Reinvested earnings	(7,542)	(9,284)
Accumulated other comprehensive income (loss)	(5)	(20)
Total shareholders’ equity	22,823	20,971
TOTAL LIABILITIES AND EQUITY	118,644	103,327
PG&E Corporation
Current Assets
Cash and cash equivalents	125	126
Advances to affiliates	46	21
Income taxes receivable	10	10
Other	12	12
Total current assets	193	169
Noncurrent Assets
Equipment	0	2
Accumulated depreciation	0	(2)
Net property, plant, and equipment	0	0
Investments in subsidiaries	33,021	30,232
Other investments	160	181
Deferred income taxes	423	297
Total noncurrent assets	33,604	30,710
TOTAL ASSETS	33,797	30,879
Current Liabilities
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)	27	27
Accounts payable – other	88	200
Other current liabilities	369	69
Total current liabilities	484	296
Noncurrent Liabilities
Long-term debt	4,588	4,592
Other	134	168
Total noncurrent liabilities	4,722	4,760
Common Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates	36,132	35,129
Reinvested earnings	(7,542)	(9,286)
Accumulated other comprehensive income (loss)	1	(20)
Total shareholders’ equity	28,591	25,823
TOTAL LIABILITIES AND EQUITY	$ 33,797	$ 30,879

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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
		Aug. 11, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Operating Activities
Net Income (Loss)			$ 1,814	$ (88)	$ (1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and tax credits, net			(452)	1,783	1,097
Reorganization items, net			0	(73)	1,458
Liabilities subject to compromise			0	0	413
Net cash provided by operating activities			3,721	2,262	(19,130)
Cash Flows from Investing Activities
Net cash used in investing activities			(10,214)	(6,905)	(7,748)
Cash Flows From Financing Activities:
Bridge facility financing fees			0	0	(73)
Repayment of long-term debt			(5,968)	(87)	(764)
Intercompany note to PG&E Corporation		$ (145)
Equity Units issued			0	0	1,304
Other			53	(29)	(40)
Net cash provided by financing activities			7,133	4,323	25,928
Net change in cash, cash equivalents, and restricted cash			640	(320)	(950)
Cash, cash equivalents, and restricted cash at January 1			307	627	1,577
Cash, cash equivalents, and restricted cash at December 31			947	307	627
Cash received (paid) for:
Interest, net of amounts capitalized			(1,607)	(1,404)	(1,563)
Income taxes, net			0	(99)	0
Noncash Investing and Financing Items [Abstract]
Common stock issued in satisfaction of liabilities			0	0	8,276
Adjustments to Treasury Stock Acquired, Noncash			2,337	(4,854)	0
PG&E Corporation
Cash Flows from Operating Activities
Net Income (Loss)			1,743	(88)	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization			95	51	28
Equity in earnings of subsidiaries			(2,160)	(139)	(412)
Deferred income taxes and tax credits, net			(126)	(60)	(50)
Reorganization items, net			0	(32)	1,548
Current income taxes receivable/payable			0	2	0
Liabilities subject to compromise			0	0	12
Other			339	81	97
Net cash provided by operating activities			(109)	(185)	(81)
Cash Flows from Investing Activities
Investment in subsidiaries			(994)	0	(12,986)
Dividends received from subsidiaries	[1]		1,275	0	0
Net cash used in investing activities			281	0	(12,986)
Cash Flows From Financing Activities:
Bridge facility financing fees			0	0	(40)
Proceeds from issuance of long-term debt			0	0	4,660
Repayment of long-term debt			(28)	(28)	(664)
Intercompany note to PG&E Corporation			(145)	145	0
Common stock issued			0	0	7,582
Equity Units issued			0	0	1,304
Other			0	(29)	0
Net cash provided by financing activities			(173)	88	12,842
Net change in cash, cash equivalents, and restricted cash			(1)	(97)	(225)
Cash, cash equivalents, and restricted cash at January 1			126	223	448
Cash, cash equivalents, and restricted cash at December 31			125	126	223
Cash received (paid) for:
Interest, net of amounts capitalized			(233)	(207)	(105)
Income taxes, net			0	1	0
Noncash Investing and Financing Items [Abstract]
Common stock issued in satisfaction of liabilities			0	0	8,276
Adjustments to Treasury Stock Acquired, Noncash			$ (2,337)	$ 4,854	$ 0

[1] Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock.

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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 171	$ 146	$ 43
Charged to Costs and Expenses	146	136	138
Charged to Other Accounts	0	0	0
Deductions	151	111	35
Balance at End of Period	$ 166	$ 171	$ 146