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, 2024
☐	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	973-7000
(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
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
6.000% Series A Mandatory Convertible Preferred Stock, no par value	PCG-PrX	The New York Stock Exchange

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, 2024, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock	$45,624 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 5, 2025:
PG&E Corporation:	2,671,320,389*
Pacific Gas and Electric Company:	264,374,809
*Includes 477,743,590 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 2025 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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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.

AB	Assembly Bill
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
ASC	accounting standards codification
ASU	accounting standard update issued by the Financial Accounting Standards Board
Bankruptcy Court	the United States Bankruptcy Court for the Northern District of California
BPPs	Bundled Procurement Plans
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
CARB	California Air Resources Board
CARE	California Alternate Rates for Energy Program
CAVA	Climate Adaptation and Vulnerability Assessment
CCA	Community Choice Aggregator
CEC	California Energy Resources Conservation and Development Commission
CEMA	Catastrophic Event Memorandum Account
Chapter 11	Chapter 11 of Title 11 of the United States Code
Chapter 11 Cases	the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
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
CPUC	California Public Utilities Commission
CRR	congestion revenue rights
DA	Direct Access
DCPP	Diablo Canyon Power Plant
District Court	United States District Court for the Northern District of California
DOE	United States Department of Energy
DOE Loan Guarantee Agreement	Loan Guarantee Agreement, dated as of January 17, 2025, between the Utility and the DOE
DTSC	California Department of Toxic Substances Control
DWR	California Department of Water Resources
Emergence Date	July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEP	Enhanced Oversight and Enforcement Process
EPA	United States Environmental Protection Agency
EPS	earnings per common share
EPSS	Enhanced Powerline Safety Settings
Exchange Act	Securities Exchange Act of 1934, as amended
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
Form 10-K	PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K
FRMMA	Fire Risk Mitigation Memorandum Account

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GAAP	United States Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
HFTD	high fire threat district
HSMA	Hazardous Substance Memorandum Account
IOUs	investor-owned utility(ies)
IRC	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
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
NBT	Net Billing Tariff
NDCTP	Nuclear Decommissioning Cost Triennial Proceeding
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OEIS	Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
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
PSPS	Public Safety Power Shutoff
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
RUBA	Residential Uncollectibles Balancing Account
SB	Senate Bill
SEC	United States Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
SFGO	The Utility’s San Francisco General Office headquarters complex
SPV	PG&E AR Facility, LLC
TCJA	Tax Cuts and Jobs Act of 2017
TO	transmission owner
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

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WEMA	Wildfire Expense Memorandum Account
WGSC	Wildfire and Gas Safety Costs
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 cost savings; 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 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; 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; 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 the OEIS that the Utility has not complied with its WMP;

•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 natural gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for natural gas; the impact of customer demand falling short of the Utility’s forecasts, driven by customer self-generation, customer departures to CCAs, direct access providers, and government-owned utilities, and legislative mandates to reduce the use of natural gas; and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, increasing demand for electric power due to electrification of the transportation and other sectors of the economy, and the resulting changes in 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;

•the Utility’s ability to attract or retain specialty personnel;

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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 DCPP operations are extended; and the Utility’s ability to continue operating DCPP 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 cybersecurity; and

◦taxes and tax audits;

•the outcome of current and future self-reports, investigations or other enforcement actions, agency compliance reports, 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 cybersecurity 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 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; 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 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, including the extent to which the Utility draws on the DOE Loan Guarantee Agreement;

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•the risks and uncertainties associated with the resolution of the Subordinated Claims and the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing or future litigation, including certain indemnity obligations to current and former officers and directors, the Wildfire-Related Non-Bankruptcy Securities Claims, and other third-party claims, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•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;

•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 high 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 pandemics and the Utility’s ability to collect on customer receivables; 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 and 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. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC located at http://www.sec.gov. 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 at http://investor.pgecorp.com, under the “Wildfire and Safety Updates” and “News & Events: Events & Presentations” 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 $200,000, a fatality or injury requiring medical attention from a healthcare professional at a hospital or other medical facility, or media coverage from a major news outlet, or a government entity investigating whether the infrastructure owned or operated by the utility caused a wildfire, 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 websites 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, Climate Strategy Report, and CAVA, which information is not incorporated by reference into this report.

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PART I

ITEM 1. BUSINESS

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in Northern and Central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. 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.

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 employees 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 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.

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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. Their focus is on making it enjoyable to work with and for PG&E Corporation and the Utility. 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 service 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, employees, and other stakeholders.

The Utility is committed to delivering a safe, reliable, sustainable, and climate-resilient energy system at the lowest possible cost 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 forward-looking climate data and tools into its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate change policy in California, and work directly with local governments and communities on adaptation solutions.

PG&E Corporation and the Utility are also committed to helping heal the planet. PG&E Corporation’s and the Utility’s 2022 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 energy system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased utilization of renewable energy combined with investments in the grid and energy storage.

PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, 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 electricity to retail customers in 2024 that was over 90% GHG free (see “Electricity Resources” below for more information).

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

•Managed contracts for more than 4.6 GW of battery energy storage to be deployed over the next several years and operated 183 MW of Utility-owned battery storage, strengthening California’s grid efficiency and reliability.

•Helped enable the total number of electric vehicles operating in the Utility’s service area to exceed 675,000; installed more than 3,800 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and deployed the first-in-the-nation 100% electric school bus fleet that is also equipped with groundbreaking vehicle-to-grid technology.

•Brought the total number of interconnected private solar customers to more than 880,000 and total number of customers who have installed battery storage at their homes or businesses to more than 120,000. These customers use their storage systems as critical backup power and for resiliency.

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•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 accelerated initiatives to meet its voluntary 2030 reduction goal. The Utility also launched an initiative to purchase California-produced renewable natural gas for its natural gas customers, toward a target to procure renewable natural gas to serve 15% of its bundled residential and small commercial demand by 2030. 

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 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. Costs can also decrease due to improved efficiencies or waste elimination.

PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing PG&E Corporation’s debt by $2 billion by the end of 2026. All three credit ratings agencies have increased PG&E Corporation’s and the Utility’s issuer credit ratings since 2020.

In December 2024, PG&E Corporation announced a new dividend policy entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. For more information, see “Liquidity and Financial Resources – Dividends” in Item 7, MD&A and Note 6 of the Notes to the Consolidated Financial Statements.

Total capital expenditures recorded in 2024 were $10.6 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be $12.9 billion for 2025, $12.0 billion for 2026, $13.6 billion for 2027, and $14.0 billion for 2028. The Utility has identified additional opportunities for investment in the coming years in addition to its forecast, including investments in transportation electrification capacity, FERC-jurisdictional assets, electric distribution capacity, hydroelectric facilities, energy storage, information technology, and automation. The Utility also plans to submit a cost recovery application for its 10-year distribution undergrounding program pursuant to SB 884. Some of these investments depend on the Utility’s ability to generate or obtain the cash to support such investments over this period of time. 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.

The Utility expects to make additional capital expenditures, the recovery of which will be subject to future regulatory approval. These expenditures include capital expenditures exceeding amounts authorized in the 2023 GRC final decision and expenditures to be included in a later filing or separate applications. These expenditures are expected to be primarily for wildfire mitigation and electrification. Additionally, $3.21 billion of fire risk mitigation capital expenditures has been excluded from the Utility’s equity base rate pursuant to AB 1054.

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PG&E Corporation and the Utility are committed to building a safe, reliable, sustainable, and climate-resilient energy system at the lowest possible cost for 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. The Utility has set a goal to increase customer capital investments while also limiting customer bill impacts, including by achieving operating cost savings, seeking efficient financing, and benefiting from electric load growth. The Utility plans to meet its cost savings goal through increased efficiencies including waste elimination through the Lean operating system. The Utility expects electric vehicle adoption, data centers, and building electrification to drive load growth. However, the scale of this growth will depend on the Utility’s ability to construct necessary infrastructure and the extent of customer demand. 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 natural 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 2023, the Utility spent $4.18 billion with certified diverse suppliers, representing 36.6% of its total spend.

Performance: Underpinning the Triple Bottom Line

PG&E Corporation and the Utility use the Lean operating system, which includes five basic “plays”: visual management; operating reviews; problem solving; standard work; and waste elimination. Visual management allows teams to see how they are performing against their most important metrics using real-time data. Teams throughout PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of employees 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 establishing 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, which drove a significant reduction in facility ignitions. PG&E Corporation’s and the Utility’s performance is also driven by an increased focus on alignment of shared outcomes among its leadership and within the organization. Waste elimination, the fifth Lean play, was deployed in 2023 and enables the companies to identify and eliminate inefficiencies in both process and workflow in a sustainable manner and drive the continued adoption of consistent processes and improvements to financial visibility and controls.

In 2023, the Utility implemented PG&E’s Safety Excellence Management System, which is a more systematic approach to assess risk and evaluate or implement controls for safe operation based on industry standards.

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 assigned for each region to deliver improved public and employee safety, customer service, and operational reliability outcomes.

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 in less than one-tenth of a second in the event of a disturbance to help prevent potential ignitions. In recent years, the Utility expanded the EPSS program to all high fire risk areas and reviewed and adjusted settings to improve coordination among devices on a circuit to reduce the number of customers impacted by an outage. 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.

•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 through the use of more granular risk models, including incorporating more detailed data inputs. The Utility has also installed sectionalizers for more targeted de-energizations of circuits and transmission lines. These more targeted scoping criteria are engineered to reduce the number of customers impacted by any particular PSPS event. In 2024, the Utility executed six PSPS events impacting a total of approximately 50,000 customers.

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•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.

•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 2024, the Utility continued to refine its inspection techniques, transitioning to the use of aerial drones to perform inspections on circuits located in HFTD areas. As a result of the improved inspection program, the Utility’s inspections in 2024 have further enhanced its ability to identify equipment conditions.

•System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTD areas and installing stronger and more resilient equipment. As the Utility’s asset inspections have identified less resilient equipment, the Utility has hardened its system by fixing significantly more equipment than in prior years. Hardening methods also 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. The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. In 2024, the Utility undergrounded 259 miles of lines. When feasible, remote grids can be a more cost-effective option to reduce fire risks by permanently disconnecting end-of-line customers from the grid and serving them with utility owned, locally sited resources. The Utility brought online five additional remote grids in 2024, for a total of 11 remote grids overall.

The Utility’s equipment was not involved in the ignition of any major wildfires in 2024. The Utility experienced an increased number of CPUC-reportable ignitions in 2024, compared to 2022 and 2023, due to hotter, drier weather conditions.

In recent years, the Utility has introduced or expanded its use of several measures including downed conductor detection, partial voltage force outs, and transmission operational controls which further decreased wildfire ignition risk and took additional steps to improve customer reliability such as vegetation management activities to reduce vegetation-caused outages, upgrading the system to improve sectionalization, and installing fault indicators to reduce restoration times. The Utility also 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 wildfire risk reduction when needed and enhancing reliability when wildfire risk is low.

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.

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 non-nuclear generation operations focus on safety, compliance, environmental stewardship, and asset reliability. The Utility focuses on continuous improvement and risk informed decision-making to maximize asset value for customers, while adhering to industry standards for asset risk management and lifecycle optimization. Work management systems enable the execution and tracking of preventative and corrective maintenance strategies for generation assets. Capital improvements are carried out to renew key asset components and are strategically aligned with interim risk reduction measures to ensure long-term safe and reliable generation.

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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 the 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 subject to the Public Utility Holding Company Act as a public utility holding company. The Public Utility Holding Company Act primarily obligates PG&E Corporation and its utility subsidiaries 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 and federal 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 broad 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 gas and electric citation programs adopted by the CPUC, the SED has discretion whether to issue a penalty for each violation. 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 and may not be recovered through rates or otherwise 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 order instituting investigation unnecessary.

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, “Regulatory Matters,” “Legislative and Regulatory Initiatives,” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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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 siting, construction, operation, maintenance, and safety obligations 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 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 15 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 DCPP and the Utility’s independent spent fuel storage installation 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 that the Utility incur substantial costs at DCPP, and substantial costs could be required in the future. For more information about DCPP, see Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Other Regulators

The CEC is a California agency with responsibility for energy policy and planning. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC establishes forecasts of future energy needs used by the CPUC in determining the adequacy of utilities’ and other load-serving entities’ electricity procurement. The CEC also promotes energy management and conservation programs, including setting standards for building and appliance energy efficiency and load management programs.

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 the Clean Air Act” below.

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 Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration has established regulations regarding the design, construction, operation, maintenance, integrity, safety, and security of natural gas distribution, transmission, and underground storage facilities. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities it regulates in California.

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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, conducting field inspections of wildfire mitigation activities, and reviewing proposed undergrounding plans under SB 884.

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. Delay in obtaining, or failure to obtain and maintain, any such permits, authorizations, or licenses could prevent construction of new facilities, limit or prevent continued operation of existing facilities, or result in significant additional costs or restrictions on operations. 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 or 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, “Liquidity and Financial Resources” and “Regulatory Matters” in Item 7. MD&A, and Notes 14 and 15 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 15 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 15 of the Notes to the Consolidated Financial Statements in Item 8.

Air Quality and the Clean Air Act

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.

At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act, which it uses to address GHG emissions.

For information regarding regulation of greenhouse gas emissions, see “Sustainability and Resiliency” below.

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 DCPP 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 DCPP 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.

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. 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 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.

As a result, the Utility’s CPUC-jurisdictional revenue requirement is the sum of the following:

•expenses;

•depreciation;

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•taxes; and

•the product of the Utility’s rate of return (i.e., the cost of capital for long-term debt and equity) and its rate base.

In addition to the Utility’s revenue requirement, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to “pass through” to customers, 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.

Customer rates are determined by dividing the revenues that the Utility is authorized to collect from customers by the amount of power that the Utility is forecasted to sell. Increases in load spread the Utility’s revenue requirement over a larger usage base, which reduces customer rates, but also increases fuel costs, which are passed through to customers.

Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through 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 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.

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. The CPUC 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 to 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 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 ratemaking capital structure (i.e., the relative weightings of common stock, preferred equity, and debt for ratemaking) and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. The rate of return, or cost of capital, is the weighted average cost of debt, preferred equity, and common stock a utility has issued to finance its utility capital investments. 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.

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Electricity Transmission Owner Rate Cases

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect through rates in TO rate cases. 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 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. 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’s GRC proceedings or that have been deliberately excluded from such proceedings. 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 through rates requires CPUC authorization in separate proceedings, the outcome of which the Utility may be unable to predict. 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 3 of the Notes to the Consolidated Financial Statements in Item 8.

Diablo Canyon Extended Operations

During the period of extended operations and in lieu of the traditional rate-based return on investment, SB 846 provides for a fixed payment of $50 million, in 2022 dollars, for each of DCPP’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, SB 846 authorizes a volumetric payment totaling $13 (in 2022 dollars) for each MWh generated by DCPP 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 DCPP. The legislation includes language that limits use of the volumetric payment to accelerate, or increase spending on, public purpose priorities enumerated in SB 846.

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 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.

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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 3 of the Notes to the Consolidated Financial Statements in Item 8. Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement. The CPUC may adjust the Utility’s retail 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 into which the Utility has entered 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 15 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, so 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. 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.

The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its Core Procurement Incentive Mechanism (“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 adjustments for under-collections and over-collections made in subsequent monthly rate changes.

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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 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 governing payments by shippers (including the Utility) for pipeline service, and the Canada Energy Regulator, the Canadian regulatory agency, approves the applicable Canadian tariffs. 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 DCPP and the Humboldt Bay independent spent fuel installation. 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, generally 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 facilities. 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 2 of the Notes to the Consolidated Financial Statements in Item 8.

Human Capital

Employees and Contractors

As of December 31, 2024, PG&E Corporation had 10 employees and the Utility had approximately 28,400 regular employees. Of the Utility’s regular employees, approximately 17,600 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, are set to 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 2024.

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PG&E Corporation’s employees are primarily at the executive management level. The Utility generally has a stable workforce. The Utility’s turnover rate for each of 2024 and 2023 was 4.0%. Approximately 44% 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 18% 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 35,000 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 virtues that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, innovation, and community service. The Utility conducts an annual employee survey to measure and improve employee engagement.

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 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. The Utility continues its expanded training for supervisors.

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 for employee health and wellness that encompass physical, mental, and financial health. These resources include several on-site or near-site health clinics, annual health screenings, health management tools, ergonomic support, and injury management programs, in addition to more traditional programs.

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 2024 STIP was focused on company objectives of safety, customer impact, and financial health.

All executive officer compensation is paid by PG&E Corporation.

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Safety

The Utility’s strategy to deliver on safety outcomes focuses on employee, contractor, and public safety. Identifying, eliminating and mitigating high-energy hazards remains a priority. The Utility’s safety metrics include the number of actual serious incidents or fatalities (“SIF-A”) and high-energy events that could have resulted in a serious injury or fatality (“SIF-P”) where SIF-P rate measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2024, the Utility had seven SIF-A incidents, which resulted in zero fatalities and seven serious injuries, and a SIF-P rate of 0.05. Additionally, the Utility measures DART (days away, restricted or transferred duty per 200,000 hours worked). In 2024, the Utility’s DART was 0.7. In particular, the Utility improved safety through the implementation of the Utility’s safety excellence management system and a focus on essential controls for high energy hazards.

Diversity, Equity, Inclusion, and Belonging

PG&E Corporation’s and the Utility’s goal is to foster a diverse, equitable, and inclusive workforce culture where all employees find it enjoyable to work with and for PG&E Corporation and the Utility and feel they belong. These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, Chief People Officer, in partnership with the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ diversity, equity, inclusion, and belonging strategy, practices, and performance.

Key elements of PG&E Corporation’s and the Utility’s approach to diversity, equity, inclusion, and belonging include integrating inclusion and belonging into the employee experience with a focus on equity and interrupting bias in hiring, promotion, retention and compensation, heightened cultural awareness programming to encourage understanding and importance of inclusion and belonging, and integrating useful content into training, development, and performance support resources.

Additionally, the Utility’s 12 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide employee programming, nominated employees lead efforts within their departments, and across the companies. Specialized teams facilitate awareness, education and dialogue and support the groups at the enterprise level.

In 2024, women, minorities, and military veterans accounted for approximately 26%, 50%, and 7%, respectively, of total PG&E Corporation and Utility employees. The Utility’s employees represent five generations, most of whom are Millennials (49%), Generation X (37%), and Boomers (10%). Generational data refers to “Millennials” for individuals born between 1981 and 1996, “Generation X” between 1965 and 1980, and “Boomers” between 1946 and 1964.

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 “Competition” below.

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.

The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to retail customers in 2024 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 is to serve 100% of retail electricity sales with GHG-free resources by 2045. For more information about California’s RPS requirements and clean energy goals, see further below and in the “Sustainability and Resiliency” section below.

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The total estimated electricity generated, procured, and sold (net), for the year ended December 31, 2024 was 26,737 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)	1	%	—	%	1	%
Nuclear (7)	63	%	—	%	63	%
Large hydroelectric	12	%	—	%	12	%
Fossil fuel-fired (4)	23	%	(22)	%	1	%
Total	99	%	(22)	%	77	%
Third-party purchase agreements
Renewable (3)	22	%	—	%	22	%
Fossil fuel-fired (4)	11	%	(10)	%	1	%
Total	33	%	(10)	%	23	%
Others, net (2)(5)	(32)	%	32	%	—	%
TOTAL	100	%	—	%	100	%
Total renewable energy resources (3)	23	%	—	%	23	%
GHG-free resources (6)	98	%	—	%	98	%

(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 Adjustment” and “Power Content Label” columns is consistent with current CEC guidelines as an adjustment mechanism to apply, as specified. 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.

(7) Amount includes adjustments due to DCPP’s extended operations, consistent with CPUC and CEC guidelines.

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. See “Sustainability and Resiliency” below. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets. The Utility expects that these costs 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.

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 23% of total annual retail sales in 2024. Per the Power Content Label methodology based on current CEC guidelines presented in the table above, an estimated 23% of the Utility’s energy deliveries were from renewable energy sources in 2024.

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The estimated total renewable deliveries for the year ended December 31, 2024, shown above was 5,920 GWh and comprised of the following:

Type	Percent of Customer Retail Sales (estimated procurement)(1)
Biopower	3	%
Geothermal	—	%
RPS-Eligible Small Hydroelectric	2	%
Solar	15	%
Wind	3	%
Total	23	%

(1) 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 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 met its requirements to make 580 MW of qualifying storage capacity operational by 2024.

As of December 31, 2024, the Utility owned 183 MW and has contracted for another 2,435 MW of operational energy storage capacity. The Utility has also procured 2,168 MW of battery energy storage to be deployed over the next several years and is working to procure additional battery energy storage to meet its remaining reliability requirements. Separately, the Utility is soliciting long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2028 and 2031. In order to address both its bundled portfolio need and to help to meet state planning and policy objectives to increase long-duration storage capacity, the Utility is pursuing regulatory approval to increase the nameplate generating capacity of its Helms Pumped Storage Facility.

Owned Generation Facilities

At December 31, 2024, 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	91	2,628
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	12	152
Total		121	7,815

(1) The Utility’s DCPP consists of two nuclear power reactor units, Units 1 and 2. The NRC operating license for Unit 1 expired in 2024. Unit 2 will expire in 2025. Both remain in effect pending completion of the ongoing federal relicensing review. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below.

(2) The Utility’s hydroelectric system consists of 94 generating units at 58 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for one small powerhouse not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.

(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.

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

Electricity Transmission

Transmission lines deliver electricity at high voltages and over long distances from power sources to transmission substations closer to customers. A strong transmission system supports reliable and affordable service, ability to meet state energy policy goals, and support for a diverse generation mix, including renewable energy.

As of December 31, 2024, 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 67,000 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

Distribution lines allow electricity to travel at lower voltages from substations directly to customers. The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2024, approximately 27% are underground and approximately 73% are overhead), 59 transmission and distribution substations, and 603 distribution substations with a capacity of approximately 33,000 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, 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 customers. In some cases, third parties, such as municipal and other utilities, who generate or procure their own power rely upon the Utility’s distribution facilities to deliver their power to them, so that they are able to 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 2022 to 2024 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 2024, 2023, or 2022.

	2024		2023		2022
Customers (average for the year)	5,606,873		5,584,185		5,562,223
Deliveries (in GWh) (1)	74,111		72,933		77,769
Revenues (in millions):
Residential	$	7,504	$	6,041	$	6,130
Commercial	7,201		5,643		5,416
Industrial	2,065		1,784		1,626
Agricultural	1,815		1,413		1,830
Public street and highway lighting	103		83		77
Other, net (2)	(47)		136		(247)
Subtotal	18,641		15,100		14,832
Regulatory balancing accounts (3)	(830)		2,324		228
Total operating revenues	$	17,811	$	17,424	$	15,060
Selected Statistics:
Average annual residential usage (kWh)	5,261		5,217		5,564
Average billed revenues per kWh:
Residential	$	0.2888	$	0.2356	$	0.2253
Commercial	0.2528		0.2007		0.1896
Industrial	0.1475		0.1294		0.1177
Agricultural	0.3597		0.2984		0.2435
Net plant investment per customer	$	11,460	$	10,720	$	9,967

(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 97% 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 2024, the Utility purchased approximately 287,000 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 50% of the total natural gas volume the Utility purchased during 2024.

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. On December 31, 2024, the Utility’s natural gas system consisted of approximately 45,200 miles of distribution pipelines, approximately 5,700 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one 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 15 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 sale of Pleasant Creek is currently pending CPUC review and approval and the Utility anticipates to close on the sale in 2025. The Utility continues to operate and rely on the Los Medanos storage field as filed and approved 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 2024, the Utility continued upgrading transmission pipelines to allow for the use of in-line inspection tools.

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Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2022 through 2024 (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 2024, 2023 or 2022.

	2024		2023		2022
Customers (average for the year) (1)	4,614,080		4,605,628		4,585,126
Gas purchased (MMcf)	219,758		239,756		227,128
Average price of natural gas purchased (price per Mcf)	$	1.99	$	6.91	$	7.42
Bundled gas sales (MMcf):
Residential	146,842		171,889		160,449
Commercial	55,174		60,248		57,066
Total Bundled Gas Sales	202,016		232,137		217,515
Revenues (in millions):
Bundled gas sales:
Residential	$	3,089	$	3,686	$	3,353
Commercial	984		1,052		1,005
Other	159		(145)		163
Bundled gas revenues	4,232		4,593		4,521
Transportation service only revenue	1,815		1,603		1,534
Subtotal	6,047		6,196		6,055
Regulatory balancing accounts (2)	561		808		565
Total operating revenues	$	6,608	$	7,004	$	6,620
Selected Statistics:
Average annual residential usage (Mcf)	37		37		37
Average billed bundled gas sales revenues per Mcf:
Residential	$	20.74	$	20.73	$	20.22
Commercial	16.28		14.99		15.19
Net plant investment per customer	$	5,019	$	4,749	$	4,522

(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.

Nuclear Operations

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 year ended December 31, 2024, DCPP achieved an average capacity factor of 93%. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of DCPP’s generation to the California electricity market and impact the Utility’s performance-based disbursements. For more information, see “Extension of Diablo Canyon Operations” below. Management analyzes capacity factors by comparing DCPP’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.

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 DCPP. 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.

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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 electric vehicle adoption, data centers, and building electrification. 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.

The Utility is also impacted by an increasing quantity 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, put upward rate pressure on non-NEM customers. The successor to the NEM tariffs, the NBT provides bill credits at a lower rate, which reduces the level of upward rate pressure on non-NEM or non-NBT customers, but does not eliminate the upward rate pressure. NEM and NBT customers are required to pay an interconnection fee, utilize time of use rates, and 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 non-NEM or non-NBT 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 “Concerns about high rates for the Utility’s customers could negatively impact PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows” in Item 1A. Risk Factors and “Regulatory Matters - Order Instituting Rulemaking (“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, in some cases bypassing the Utility’s electric infrastructure entirely. Those entities may also rely upon FERC open access tariffs and Utility infrastructure to deliver their energy 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) or experience limited growth in the municipality. See “Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system” 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, bypassing the Utility’s electric infrastructure. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities. Some private companies have also called for changes in law that could allow those companies to privately serve electricity to retail customers without being regulated by the CPUC as public utilities. To the extent such changes occur and result in large customers reducing the share of transmission, distribution, and non-bypassable charges they pay, PG&E Corporation’s and the Utility’s financial condition and results of operations could be materially impacted.

The effect of such types of retail competition generally is to reduce the number of utility customers, leading to decreased growth or 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.

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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.

Sustainability and Resiliency

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. 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, increased electricity demand driven by rising air conditioning installation and usage, and continued electrification of transportation and buildings. Higher temperatures may also impact the condition and performance of electric assets, potentially causing deterioration of assets and operational constraints.

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. 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 equipment 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 worsening conditions across California increase the likelihood and severity of wildfires, including those in which 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.

Greenhouse Gas Emissions Regulation

California laws and regulations have established the following targets:

•A 40% reduction in GHGs by 2030 compared to 1990 levels.

•50% of retail energy sales to customers from renewable energy sources by 2026 and 60% by 2030.

•Economy-wide State carbon neutrality by 2045, with net negative emissions thereafter.

•Renewable and zero-carbon resources supplying 90% of utilities’ retail sales to customers by 2035, 95% by 2040, and 100% by 2045.

The CARB has also approved 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 has been extended through 2030. The CARB plans to update the cap-and-trade regulation in 2025 and is considering reforms that would reduce overall allowance budgets to align with CARB’s 2022 Climate Change Scoping Plan.

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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 methane capture projects). The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.

The cap-and-trade program applies to the electric generation, large industrial, natural gas, 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 obligations.

The federal administration of President Trump has led to uncertainty with regard to what further actions may occur regarding climate change at the federal level.

Mitigating Greenhouse Gas Emissions

The Utility works to mitigate the impact of its operations (including customer energy usage) on the environment, consistent with its commitment to clean and resilient energy for all. See “Emissions Data” below.

PG&E Corporation’s and the Utility’s 2022 Climate Strategy Report, which is available to the public, describes the companies’ climate goals and plans to meet those goals. California laws and regulations have also established targets for GHG emissions. See “Greenhouse Gas Emissions Regulation” above.

The core elements of the Utility’s plan to achieve these goals are to:

•reduce its operational emissions;

•maximize electrification where feasible;

•integrate clean electricity supply and load management solutions;

•modernize the gas system into an essential low-carbon resource; and

•offset remaining emissions through high-quality carbon removal solutions.

To reduce operational emissions, the Utility plans to take steps such as reducing methane leaks from its natural gas system, reducing sulfur hexafluoride emissions from the electric system, and electrifying its vehicles, buildings, and facilities.

To maximize electrification, the Utility plans to enable and scale building electrification, supported by building codes and appliance standards that give preference to electric technologies, as well as customers choosing to adopt electric appliances. The Utility can accelerate customer adoption of electric vehicles by offering customer programs, preparing the grid to accommodate new electric vehicle demand, and partnering with innovators on strategies that reduce the cost of owning an electric vehicle.

Load management solutions can increase utilization of the electric infrastructure system, such as by using distributed energy resources more strategically and enabling technologies for customers like bidirectional charging.

To integrate clean electricity supply, the Utility plans to continue to expand GHG-free energy resources and storage capacity over the long-term to meet California’s Integrated Resource Planning (“IRP”) GHG emissions reduction targets and California’s clean energy goals. The Utility expects its GHG-free energy supply to decrease in the near future because, during DCPP’s extended operations, the Utility is required to allocate its GHG-free attributes to certain non-Utility providers. The Utility also allocates or sells certain GHG-free energy supply to eligible non-Utility providers in its service territory pursuant to CPUC directives.

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Modernizing the gas system involves reducing natural gas carbon intensity through clean fuels and decarbonizing hard-to-electrify customers. Clean renewable fuels such as renewable natural gas, which is derived from organic waste, offers a sustainable alternative to fossil fuel-based gas. While still early in assessing its potential, the Utility may also blend a safe amount of hydrogen for customers in the future, if authorized.

The Utility’s ability to implement this plan depends on many factors, such as customers adopting technologies and behaviors that reduce GHG emissions and supportive federal, state, and local climate policies and programs, including regulatory innovations needed to reduce unnecessary new costs for the energy system. New and maturing technologies will need to become effective and efficient. Additionally, the Utility will need to construct infrastructure to serve customer demand and implement load management solutions in a way that is affordable for customers. This affordable construction depends on PG&E Corporation’s and the Utility’s receiving sufficient funding through their ratemaking applications, dedicating adequate resources, efficiently financing operations, achieving operational cost savings, and benefiting from load growth.

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.

A key element of preparing the Utility for the physical risks of climate change is a system-wide CAVA of the Utility’s assets, operations, and services, filed with the CPUC in May 2024. The CAVA improves the Utility’s understanding of its exposure to climate hazards and the sensitivity of assets and operations to these hazards, and provides the basis for necessary climate resilience investments.

The Utility is using the CAVA to inform changes to design and construction standards for equipment and facilities, in order to increase infrastructure resilience. The Utility plans to continue identifying priority adaptive actions by incorporating results from the CAVA into its risk management, planning, and asset management functions. The Utility works to incorporate into its operations scientific information by reviewing relevant scientific literature and to incorporate customer and community perspectives based on its engagement with CPUC-designated disadvantaged and vulnerable communities in the CAVA process.

The Utility’s commitment to increasing resilience to climate change includes aligning its resources and business strategy with California’s clean energy goals, 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 a portfolio of customer programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected increases in demand for electricity.

PG&E Corporation and the Utility are also making progress on transitioning the gas system to cleaner fuels and supporting 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.

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 following table shows the Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2023, 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.

Emissions Scope	Amount (metric tons CO2 equivalent)
Scope 1 and 2 emissions (1)	4,026,490
Scope 3 emissions (2)	39,446,426

(1) Scope 1 emissions are direct emissions from the Utility’s operations and Scope 2 emissions are indirect emissions from facility electricity use and electric line losses.

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(2) Scope 3 emissions are emissions resulting from downstream value chain activities not owned or controlled by the Utility but that which can be indirectly impacted by the Utility’s actions. The majority of these emissions came from customer natural gas use.

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 2023. This resulted in a third-party verified CO2 emissions rate of 12 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.

	2023	2022
Total NOx emissions (tons)	139	121
NOx emissions rate (pounds/MWh)	0.01	0.01
Total SO2 emissions (tons)	13	11
SO2 emissions rate (pounds/MWh)	0.001	0.001

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 2024 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 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires;

•Recovery of excess costs in connection with wildfires; and

•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 natural gas industries;

•A cyber incident, cybersecurity breach, or physical attack;

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

•Attracting and retaining specialty personnel.

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Risks related to environmental factors, including risks related to:

•Severe weather events, 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;

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

•Attempts to acquire the Utility's assets and customers through municipalization or bypass.

Risks related to financial conditions, including risks related to:

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

•Restrictions in indebtedness documents;

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

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

•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;

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

•The Utility’s ability to manage its costs effectively;

•Increased customer rates; and

•Inflation and supply chain issues.

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 all aspects of the 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 14 of the Notes to the Consolidated Financial Statements in Item 8.

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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 PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund (see Note 2 of the Notes to the Consolidated Financial Statements in Item 8), including as a result of claims made by California’s other participating electric utility companies. For example, victims of wildfires in Southern California in January 2025 have filed lawsuits alleging that Southern California Edison’s equipment was associated with the ignition of such fires.

If the Utility is unable to maintain a safety certification or if the Wildfire Fund is exhausted, the ineffectiveness of 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.

In addition, there could be a significant delay between the occurrence of a wildfire and when 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 the benefits of participating in the Wildfire Fund may not ultimately outweigh the substantial costs of the Utility’s contributions to the Wildfire Fund.

PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2021 Dixie fire, or the 2022 Mosquito fire could exceed their accruals, or they could be liable as a result of 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 2021 Dixie fire, and the 2022 Mosquito fire. PG&E Corporation’s and the Utility’s recorded liabilities for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. 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 been the subject of investigations, regulatory enforcement actions, and criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, 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.

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. The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in litigation against PG&E Corporation or the Utility.

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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. The Utility’s significant infrastructure investment, vegetation management, and de-energization strategies do not eliminate wildfire risk and may not prevent future wildfires. Once an ignition has occurred, the Utility is unable to control the extent of damages, which 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 and the FERC, and future regulatory proceedings, including future applications with the OEIS for the annual safety certification. 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 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires. For more information about the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 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.

PG&E Corporation’s and the Utility’s accrued losses for the 2019 Kincade fire and the 2021 Dixie fire of $1.225 billion and $1.925 billion exceed the amounts of available liability insurance coverage of $430 million and $527 million, respectively. PG&E Corporation and the Utility could also incur substantial costs in excess of insurance coverage in connection with the 2022 Mosquito fire. As of December 31, 2024, the Utility has recorded probable recoveries of $602 million and $60 million for the 2021 Dixie fire and 2022 Mosquito fire, respectively, through FERC TO rates or as costs recorded to the WEMA. The Utility would not be allowed to recover these costs in excess of insurance to the extent that the CPUC or the FERC determines that they were incurred imprudently. The inability to recover all or a significant portion of costs in excess of insurance through rates 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 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility may not effectively implement its wildfire mitigation initiatives.

The Utility’s infrastructure is aging and poses risks to safety and system reliability. The Utility’s wildfire mitigation initiatives may not be successful or effective in preventing or 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, or 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.

Wildfires can occur even when the Utility follows its procedures. 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.

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.

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Risks Related to Operations and Information Technology

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

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, some of which are beyond the Utility’s control, including those that arise from:

•the breakdown, failure of, or supply challenges with 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;

•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 significant prolonged electrical black-out that results in damage to the Utility’s equipment or losses for 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;

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•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; leaking or spilled insulating fluid from electrical equipment; and release of contaminants caused by the failure of battery energy storage systems; 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, cybersecurity breach, 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. The Utility has less control over contractors than its employees but may retain liability for the quality and completion of the contractor’s work. The Utility has been and may in the future be subject to penalties or other enforcement action if a contractor violates applicable laws, rules, regulations, or orders. The Utility also has been and may 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.

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 natural gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could lead to the reduction in demand for natural gas as an energy resource that could impact the Utility’s ability to recover the value of its investments through rates.

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, electric heat pump space conditioning and water heating, battery electric storage, fuel cells, energy efficiency, and demand response technologies. These developments will require further modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, enabling California’s clean energy transition will require sustained investments in grid modernization, renewable energy 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 reduces the gas customer base and could diminish the need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful” (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which may result in a reduction in associated rate recovery). In that case, gas assets with substantial investment value could become stranded, resulting in accelerated depreciation or impairment of assets. The Utility could also be required to incur significant decommissioning costs, which may require additional funding. However, even as 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. If the Utility is unable to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability, its financial condition, results of operations, liquidity, and cash flows could be materially affected.

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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, cybersecurity breach, 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 physical and cyber attacks. Nationally, there has been an increase in physical attacks on substations. Physical attacks targeting the Utility’s physical assets or personnel could cause damage, disrupt operations, or cause injuries. Cyber attacks targeting utility systems are significant and are continuing to increase in sophistication, magnitude, and frequency. Any failure, interruption, 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 a safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.

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, and portions of such sensitive information may be required to be encrypted by the Utility. 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. The Utility often relies on third-party vendors to host, maintain, modify, and update its systems (including providing security updates), and to provide other services to the Utility or the Utility’s customers. These third-party vendors could cease to exist, fail to adopt and implement adequate processes to protect the Utility’s systems and information, fail to provide timely software updates (and even if timely provided, there could be a delay in the installation of the updates), fail to detect security vulnerabilities, or experience security incidents or inadequate security measures. Any such 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.

PG&E Corporation and the Utility face various cybersecurity threats, including attempts to gain unauthorized access to their systems and networks, denial-of-service attacks, threats to their information technology infrastructure, ransomware and phishing attacks, and attempts to gain unauthorized access to confidential or sensitive information about the Utility, customers and employees. These threats come from a variety of highly organized actors, including nation-state actors. PG&E Corporation, the Utility and their third-party vendors have been subject to, and will likely continue to be subject to, threats, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential or sensitive data (including information about customers and employees), or to disrupt the Utility’s operations. Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats, and PG&E Corporation’s and the Utility’s use of generative artificial intelligence (and use by their vendors and agents) may subject them to data privacy, legal, and security risks. The Utility may not 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, lawsuits, and regulatory actions and could result in material fines, 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 business strategy, financial condition, or results of operations. For more information, see Item 1C. Cybersecurity.

The Utility maintains cyber liability insurance that covers certain losses and damages caused by cyber incidents, but adequate insurance may not continue to be available at rates the Utility believes are reasonable, or the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable through rates.

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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 DCPP 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 $332 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s DCPP facility but at any other nuclear power plant in the United States.

New legislation, regulations, orders, or their interpretation could increase the Utility’s costs to operate DCPP or lead to the Utility ceasing operations at DCPP. 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. 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. As a result, 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. Operations at the Utility’s two nuclear generation units at DCPP could cease before their planned retirement dates in 2029 and 2030. In such an instance, the Utility would not receive the payments for extended operations at DCPP and could be required to record a charge for the remaining amount of its unrecovered investment. These developments 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 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 2 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, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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

The Utility’s workforce is aging, and many employees are or will become eligible to retire within the next few years. The Utility’s efforts to recruit and train new field service personnel may be ineffective, and the Utility may be faced with a shortage of experienced and qualified personnel in certain specialty operational positions, such as certain positions at DCPP. Additionally, the Utility could experience workforce disruptions from personnel in those positions as a result of labor activity, pandemics, or governmental regulation of pandemic protections. 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.

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Risks Related to Environmental Factors

Severe weather events, 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. Precipitation patterns in California vary significantly from year to year, often leading to periods of severe to extreme drought. Drought conditions often occur and can persist in nearly all of the Utility’s service area depending on the amount of precipitation received in the current or previous water years. 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 5,000 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs.

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, could result in severe business or operational 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 have damaged and could again damage the Utility’s facilities. The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries, or regulators could order the Utility to perform additional work. The Utility anticipates that the increased costs would generally be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. See “Concerns about high rates for the Utility’s customers could negatively impact PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows” 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.

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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 or may be identified as a potentially responsible party under federal and state environmental laws. These costs can be difficult to estimate due to uncertainties about the extent of contamination, emerging contaminants, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties, and the Utility’s recorded liabilities for known environmental obligations may not accurately estimate its losses. For more information, see Note 15 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 or regulation, 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 15 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.

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 incur significant costs to comply with laws and regulations and be adversely 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.

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Privacy

PG&E Corporation and the Utility collect and retain certain personal information of their customers, shareholders, and employees in connection with their business. The State of California has enacted privacy laws in recent years, and final regulations under the California Privacy Rights Act are under development. PG&E Corporation’s and the Utility’s risk management and information security measures may be ineffective, and 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 data sharing with third parties.

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 material fines being imposed on PG&E Corporation and the Utility.

The Utility develops its capital plans based on forecasts, including those around load growth, gas system planning, and transportation electrification, which assume that California continues to pursue consistent environmental policies. If the federal government withdraws its support for grid modernization or prohibits California from pursuing its environmental policies, or if California changes its policies, PG&E Corporation and the Utility may be unable to meet their environmental and financial goals.

Tax

The Inflation Reduction Act includes a 15% corporate alternative minimum tax 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. If the law or its interpretation is not changed to permit PG&E Corporation to deduct repairs and maintenance expense, it will incur federal cash liabilities beginning in 2027, the amount of which may become substantial in future years. See Legislative and Regulatory Initiatives in Item 8. MD&A.

The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with such regulations could result in penalties.

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 matters that the CPUC’s SED may investigate. The SED can launch investigations at any time on any issue it deems appropriate. In addition, the 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; wildfire mitigation initiatives (including EPSS, PSPS, vegetation management, asset inspections, and system hardening); design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC general orders (“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.

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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. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions. The Utility is unable to predict the outcome of these pending or potential 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, penalties, customer rebates, or other payments, 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.

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.

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 have not allowed and may in the future 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, wildfire mitigation and prevention costs before it is clear whether such costs will be recoverable through rates. OEIS has required and may in the future require the Utility to perform work for which the CPUC has not yet authorized recovery. 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 without cost recovery 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), whether the CAISO wholesale electricity market continues to function effectively, or compliance with new state laws or policies. See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1.

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Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system.

Jurisdictions attempt to acquire the Utility’s assets through eminent domain (“municipalization”). For example, 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 or serving San Francisco and has expressed intent to acquire such assets. 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, but the Utility may not 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, as well as associated severance damages, but 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. In addition, third parties attempt to bypass the Utility’s existing electric infrastructure system to provide retail electric service to discrete geographic areas or specific customers. Utility assets that are targeted for municipalization, as well as existing or potential future Utility customers targeted for electric services by third parties that bypass the Utility’s facilities, generally are located in geographic areas that have a lower cost of service relative to billed revenues, so municipalization (or bypass) could negatively impact the affordability of the Utility’s service for remaining Utility customers served outside of those geographic areas. A successful municipalization or bypass attempt could also encourage similar attempts by other municipalities or third parties 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 any involuntary sale of its assets between shareholders and customers. As a result of these factors, municipalization or electric bypass 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, 2024, PG&E Corporation had approximately $5.65 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.5 billion aggregate principal amount of Junior Subordinated Notes due 2055, $1.0 billion aggregate principal amount of senior secured notes due 2028, and $1.0 billion aggregate principal amount of senior secured notes due 2030, and the Utility had approximately $51.9 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 $3.8 billion of additional borrowing capacity under the Utility Revolving Credit Agreement and $1.5 billion under the Receivables Securitization Program. In addition, PG&E Corporation and the Utility had outstanding preferred stock with aggregate liquidation preferences of $1.6 billion and $258 million, respectively.

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 or using them for other financing transactions. 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;

•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.

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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, particularly investment grade 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. Although the Utility is generally entitled to seek recovery of its cost of capital, because such requests are subject to CPUC review, the Utility may not successfully recover its cost of capital. Even when cost recovery is granted, the timing of such recovery will generally not occur until after the costs are required to be paid. 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.

In addition, the Utility’s DOE Loan Guarantee Agreement contains similar covenants as well as certain affirmative and negative covenants, events of default, and prepayment events which are incremental to those contained in the Utility’s credit agreements and indentures.

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. 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. Failure to comply with these covenants could result in an event of default, which, if not cured or waived, could accelerate PG&E Corporation’s or the Utility’s repayment obligations and could result in a default, acceleration or other consequences under other agreements. For example, a default on indebtedness in a principal amount in excess of $200 million could result in a cross-default or cross-acceleration.

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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 “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14 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 “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14 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.

PG&E Corporation capital 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 incur in the future 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 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.

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 combined value of 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 combined value of the Equity Securities to increase their proportionate interest in the Equity Securities. Additionally, 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 differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility. See “Tax Matters” in Item 7. MD&A for an example of these calculations. 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.

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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, 2024, 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 $33.7 billion and $34.9 billion, respectively, and PG&E Corporation incurred and may also continue to incur 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 value of the 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 an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan or in combination with other changes in the ownership of PG&E Corporation’s equity depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects. Accordingly, the IRS may successfully assert that PG&E Corporation has undergone an ownership change pursuant to the Plan. If the IRS 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. 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 capital stock.

PG&E Corporation is a holding company and relies on dividends, distributions, and other payments, advances, and transfers of funds from the Utility to pay dividends on its capital stock and 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, ability to pay dividends on its capital stock, and ability to meet its debt service obligations under its existing and future indebtedness largely depend upon the earnings and cash flows of the Utility and the distribution of these earnings and cash flows to PG&E Corporation. 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 is restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in financing agreements. See “Liquidity and Financial Resources” in Item 7. MD&A. 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 meet its obligations to employees and creditors, and to pay preferred stock dividends, before it can distribute cash to PG&E Corporation. In particular, the CPUC requires PG&E Corporation’s and the Utility’s Boards of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC also regulates the Utility’s capital structure. Dividend payments on PG&E Corporation’s capital stock are also subject to the discretion of PG&E Corporation’s Board of Directors. See Note 6 of the Notes to the Consolidated Financial Statements included in Item 1.

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 make other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to pay capital stock dividends or meet other obligations.

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The Utility may be unable to manage its costs effectively.

The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility’s ability to achieve such savings depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system. Even if the Utility is able to reduce some costs, other emerging priorities, such as emergency response, public purpose programs, wildfire mitigation initiatives, or California’s clean energy transition, could require it to reinvest those savings.

Concerns about high rates for the Utility’s customers could negatively impact PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customers’ rates. In particular, the Utility will need to make substantial, sustained investments to its infrastructure to adapt to climate change, enable the clean energy transition, and mitigate wildfire risk. Other factors that could increase customer rates include increases in the Utility’s pass-through commodity costs, cost shifts resulting from self-generation of electricity by customers, decreased gas system load, technological developments, changes in federal or state subsidies, a decrease in the volume of sales, or load growth that is slower than PG&E Corporation and the Utility forecast. High rates could also lead to a decline in the number of customers, which could further increase rates. 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” above.

The CPUC considers affordability as it adjudicates the Utility’s rate cases, and concerns about affordability could cause the CPUC to approve lesser amounts in the Utility’s ratemaking or cost recovery proceedings.

To relieve upward rate pressure, the CPUC has authorized and may in the future authorize lower revenues than the Utility requested or increase the period over which the Utility is allowed to recover amounts. The Utility’s level of authorized capital investment could decline as well, leading to fewer new business interconnections and 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 and supply chain issues may adversely affect PG&E Corporation and the Utility.

PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased and may continue to increase more quickly than expected as a result of inflation or tariffs. Additionally, the Utility has experienced shortages in certain items, 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 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 affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 1C. CYBERSECURITY

Risk Management and Strategy

The objective of PG&E Corporation’s and the Utility’s cybersecurity program is to protect information assets and to mitigate against material cybersecurity threats, data and information compromise, and other risk events that could materially affect the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk, such as:

•Developing organizational understanding in managing cybersecurity risks to systems, assets, and data by regularly assessing cybersecurity internal controls and program maturity, including engaging independent third parties and participating in external regulatory compliance assessments;

•Assessing, monitoring, and imposing contractual requirements on third-party service providers for cybersecurity risks and for compliance with PG&E Corporation’s and the Utility’s policies regarding access to company networks, information security, and technology;

•Configuring and monitoring the system; employing policies, controls, and security tools, including training for employees and contractors; and limiting access and operating firewall rules as necessary and appropriate;

•Utilizing multiple government and private assessors, consultants, auditors or other third parties, as well as an internal team, for intelligence gathering, security monitoring, threat hunting, and forensic activities;

•Monitoring emerging data protection laws and regulations and implementing changes to processes designed to comply with any such laws and regulations;

•Responding to cybersecurity incidents as they are detected by containing consequences, investigating causes and impacts, and implementing mitigations;

•Maintaining and utilizing plans for resilience, mitigation, and restoring any capabilities or services that were impaired due to a cybersecurity incident;

•Maintaining cybersecurity liability insurance;

•Maintaining physical controls on a risk-informed basis, including controlling access or monitoring as appropriate; and

•Continuously improving the cybersecurity program by incorporating learning from past experiences and testing, reviewing, and enhancing the controls and capabilities discussed above, including conducting regular cybersecurity incident-response exercises.

PG&E Corporation and the Utility have identified cybersecurity as a key enterprise risk, which they manage through their enterprise risk management system.

PG&E Corporation and the Utility have not experienced any cybersecurity incidents in the last three years that have materially affected the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. For more information regarding how cybersecurity threats could materially affect PG&E Corporation and the Utility, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack.” in Item 1A. Risk Factors.

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Governance

PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, have primary responsibility for overseeing cybersecurity risk management, including reviewing the companies’ cybersecurity policies, controls, and procedures. The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats. In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.

The Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions. They are responsible for assessing and managing cybersecurity risks in collaboration with the enterprise risk management team. Such persons are informed about cybersecurity vulnerabilities and incidents through daily and weekly operating reviews conducted by management and personnel closest to the work as part of the Lean operating system and as otherwise appropriate.

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”, “Natural Gas Utility Operations,” and “Nuclear 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 approximately 7.5 million square feet of real property, including 5.5 million square feet owned by the Utility. Virtually all of the Utility’s plant property is subject to the lien of a first mortgage bond indenture.

The Utility leases the Lakeside Building and has exercised an option to purchase the Property. The Utility will continue to lease the Property until closing in June 2025. For more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility owns over 135,000 acres of land, including approximately 100,000 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. In 2024, the Utility met its goal to permanently preserve the approximate 140,000 acres of watershed lands, after securing all required regulatory approvals.

ITEM 3. LEGAL PROCEEDINGS

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business.  For more information regarding material lawsuits and proceedings, see “Litigation Matters” in Item 7. MD&A, Item 1A. Risk Factors and Notes 9, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8.

Each of PG&E Corporation and the Utility has elected use $1 million as the quantitative threshold for disclosure of environmental proceedings described in Item 103(c)(3)(iii) of Regulation S-K.

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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 the Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. The Utility continues to work with the California Coastal Commission and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues. 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 have recorded charges for amounts that are 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.

Butte Canal Breach

On August 9, 2023, a canal in Butte County owned by the Utility breached. The Central Valley Regional Water Quality Control Board has alleged environmental violations in connection with the breach. 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, but the amount of the liability is not reasonably estimable. PG&E Corporation and the Utility do not believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

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 12, 2025. 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	56	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
Carolyn J. Burke	57	Executive Vice President and Chief Financial Officer	May 4, 2023 to present
		Chief Financial Officer & Executive Vice President, Chevron Phillips Chemical Company LLC	February 2019 to September 2022
		Senior positions, including Executive Vice President, Strategy & Administration, Dynegy, Inc.	August 2011 to April 2018
Kaled H. Awada	50	Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company	January 16, 2024 to present
		Executive Vice President & Chief Human Resources Officer, Tenneco Inc.	September 2018 to November 2022
		Global Vice President, Human Resources, Aptiv PLC	May 2015 to August 2018

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Jason M. Glickman	44	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
Carla J. Peterman	46	Executive Vice President, Corporate Affairs and Chief Sustainability Officer	October 1, 2021 to present
		Executive Vice President, Corporate Affairs	June 2021 to September 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
Marlene M. Santos	64	Executive Vice President and Chief Customer and Enterprise Solutions Officer, Pacific Gas and Electric Company	October 16, 2023 to present
		Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company	March 15, 2021 to October 15, 2023
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
John R. Simon	60	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
		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
Sumeet Singh	46	Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company	March 1, 2023 to present
		Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to February 28, 2023
		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

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		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
Ajay Waghray	63	Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2024 to present
		Executive Vice President and Chief Information Officer, PG&E Corporation	July 1, 2023 to December 31, 2023
		Senior Vice President and Chief Information Officer	September 21, 2020 to June 30, 2023
		Founder, Agni Growth Ventures, LLC	January 2019 to September 2021
		Executive Vice President and Chief Technology Officer, Assurant Inc.	May 2016 to December 2018

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The following individuals serve as executive officers of the Utility as of February 12, 2025. Except as otherwise noted, all positions have been held at the Utility.

Jason M. Glickman	44	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
		Consultant, Bain & Company	August 2007 to December 2013
Marlene M. Santos	64	Executive Vice President and Chief Customer and Enterprise Solutions Officer	October 16, 2023 to present
		Executive Vice President and Chief Customer Officer	March 15, 2021 to October 15, 2023
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
Sumeet Singh	46	Executive Vice President, Operations and Chief Operating Officer	March 1, 2023 to present
		Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to February 28, 2023
		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
Stephanie N. Williams	42	Vice President, Chief Financial Officer and Controller	January 10, 2023 to present
		Vice President and Controller, PG&E Corporation	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
Kaled H. Awada	50	Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company	January 16, 2024 to present

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		Executive Vice President & Chief Human Resources Officer, Tenneco Inc.	September 2018 to November 2022
		Global Vice President, Human Resources, Aptiv PLC	May 2015 to August 2018
Ajay Waghray	63	Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2024 to present
		Executive Vice President and Chief Information Officer, PG&E Corporation	July 1, 2023 to December 31, 2023
		Senior Vice President and Chief Information Officer	September 21, 2020 to June 30, 2023
		Founder, Agni Growth Ventures, LLC	January 2019 to September 2021
		Executive Vice President and Chief Technology Officer, Assurant Inc.	May 2016 to December 2018

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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 5, 2025, there were 40,511 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 6 of the Notes to the Consolidated Financial Statements in Item 8.

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.

Generally, PG&E Corporation’s and the Utility’s revenues vary based on the outcomes of ratemaking proceedings and the amount of pass-through costs incurred. See “Ratemaking Mechanisms” in Item 1. Description of the Business regarding how the Utility’s revenues are determined. Factors that cause costs to vary include the cost of purchased power and fuel; the costs of procurement storage, transportation of natural gas; weather; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances.

The discussion related to the results of operations and liquidity for 2023 compared to 2022 is incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC in February 2024.

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, self-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 (such as undergrounding). The Utility’s wildfire mitigation efforts have also benefited in recent years from improved ignition response and situational awareness tools like weather stations and risk modeling. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned from utility-related ignitions. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.

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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 3 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 continually reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the OEIS as its review progresses. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

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 may be 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, 2024, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.225 billion, $1.925 billion, and $100 million for claims in connection with the 2019 Kincade 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.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance 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 14 of the Notes to the Consolidated Financial Statements in Item 8.

As of December 31, 2024, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $527 million for the 2021 Dixie fire, and $90 million for the 2022 Mosquito fire. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies.

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. The Utility has recorded an aggregate Wildfire Fund receivable of $925 million for the 2021 Dixie fire, of which it had received $169 million as of December 31, 2024. See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable 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, 2024, the Utility has recorded receivables for regulatory recovery of $602 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information.

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•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). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, 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. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. 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 3 and 15 of the Notes to the Consolidated Financial Statements in Item 8, and “Regulatory Matters” below.

•PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing 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 long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to minimize financing costs by identifying and executing on opportunities to efficiently finance the business, which depends on capital market conditions.

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 and “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $33.7 billion and a California net operating loss carryforward of approximately $34.9 billion as of December 31, 2024.

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 value of 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 and Restated Articles of Incorporation, 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 (the “Amended Articles”) contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore 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. Accordingly, although PG&E Corporation had 2,671,320,389 common shares outstanding as of February 5, 2025, only 2,193,576,799 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date. For example, based on the closing prices of PG&E Corporation’s common stock and preferred stock as of February 5, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 5, 2025 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation.

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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RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2024 and 2023.  See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

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

(in millions)	2024		2023
Consolidated Total	$	2,475	$	2,242
PG&E Corporation	(223)		(288)
Utility	2,698		2,530

PG&E Corporation’s net loss primarily consists of interest expense on long-term debt.

Utility

The table below shows the Utility’s Consolidated Statements of Income for 2024 and 2023.  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 Net income.

	Year Ended December 31,
(in millions)	2024		2023
Electric operating revenues	$	17,811	$	17,424
Natural gas operating revenues	6,608		7,004
Total operating revenues	24,419		24,428
Cost of electricity	2,261		2,443
Cost of natural gas	1,192		1,754
Operating and maintenance	11,787		11,913
SB 901 securitization charges, net	33		1,267
Wildfire-related claims, net of recoveries	94		64
Wildfire Fund expense	383		567
Depreciation, amortization, and decommissioning	4,189		3,738
Total operating expenses	19,939		21,746
Operating income	4,480		2,682
Interest income	589		593
Interest expense	(2,781)		(2,485)
Other income, net	319		293
Income before income taxes	2,607		1,083
Income tax benefit	(105)		(1,461)
Net income	2,712		2,544
Preferred stock dividend requirement	14		14
Income Attributable to Common Stock	$	2,698	$	2,530

Operating Revenues

The Utility’s electric and natural gas operating revenues decreased by $9 million, or 0%, in 2024 compared to 2023. These decreases were primarily due to:

•a decrease in revenues to recover the cost of electricity procurement (which decreased by $182 million) and the cost of natural gas (which decreased by $562 million) and the cost of public purpose programs (which decreased by approximately $50 million) in 2024. These costs are passed through to customers and do not impact net income. (See “Cost of Electricity”, “Cost of Natural Gas”, and “Operating and Maintenance” below);

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•approximately $585 million in revenues authorized in the 2020 WMCE proceeding in 2023 with no similar amount in 2024;

•a decrease of approximately $345 million in revenues to recover insurance costs related to the Utility’s adoption of self-insurance in 2024;

•a decrease of approximately $310 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below); and

•a decrease of approximately $230 million in revenues to recover costs associated with a lower allowance for doubtful accounts from residential customers in 2024. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8).

Partially offset by:

•approximately $1.0 billion in increased base revenues authorized in the 2023 GRC;

•approximately $390 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in 2024 with no similar amount in 2023;

•an increase of approximately $310 million in revenues authorized through the FERC formula rate;

•approximately $205 million in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in 2024 with no similar amount in 2023;

•approximately $170 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2024 with no similar amount in 2023; and

•approximately $85 million related to the 2021 NDCTP final decision that ordered the Utility to issue a refund of the Non-Qualified Trust to customers in 2023 with no comparable refund in 2024.

Cost of Electricity

The Utility’s cost of electricity represents the cost of power and fuel used in the Utility’s generating facilities and purchased from third parties to serve customers. Cost of electricity includes fuel supplied to other third-party generating facilities, costs to comply with California’s cap-and-trade program, realized gains and losses on price risk management activities (see Note 10 of the Notes to the Consolidated Financial Statements in Item 8), and net power purchases from and sales to the CAISO electricity markets and directly from third parties. The cost of electricity decreased by $182 million in 2024 as compared to 2023. These decreases were primarily the result of lower natural gas market prices included as fuels costs for applicable Utility or third-party generating facilities, partially offset by lower net CAISO market sales revenues.

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 10 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas decreased by $562 million in 2024 as compared to 2023. These decreases were primarily the result of lower natural gas procurement costs, partially offset by less favorable price risk management results, both of which were due to lower natural gas market prices for the period.

Operating and Maintenance

The Utility’s operating and maintenance expenses decreased by $126 million, or 1%, in 2024 compared to 2023. These decreases were primarily due to:

•the recognition of approximately $420 million in previously deferred expenses authorized in the 2020 WMCE proceeding in 2023 with no similar amount in 2024;

•a decrease of approximately $345 million in insurance costs related to the Utility’s adoption of self-insurance in 2024;

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•a decrease of approximately $230 million in costs associated with a lower allowance for doubtful accounts from residential customers in 2024. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8);

•a decrease of approximately $160 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) in 2023; and

•a decrease of approximately $50 million in pass-through costs related to public purpose programs in 2024. These costs are passed through to customers and do not impact net income (see “Operating Revenues” above).

Partially offset by:

•approximately $390 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in 2024;

•approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to reclassify these costs to operating expense in 2024;

•approximately $175 million in revenues authorized in the GOSMA petition for modification final decision in 2024 with no similar amount in 2023;

•approximately $170 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2024 with no similar amount in 2023;

•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in 2024; and

•an increase in labor and benefit costs in 2024.

SB 901 Securitization Charges, Net

The Utility’s SB 901 securitization charges, net decreased by $1.23 billion, or 97%, in 2024 compared to 2023. These decreases were due to the recognition of $1.27 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023, with no comparable activity in 2024. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below.

Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires increased by $30 million, or 47%, in 2024 compared to 2023. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund and WEMA and $100 million related to the 2019 Kincade fire in 2023. The Utility recognized pre-tax charges of $325 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund and $100 million related to the 2019 Kincade fire in 2024. Additionally, in 2024, probable WEMA recoveries increased by approximately $30 million due to a reclassification between WEMA and FERC recoveries, which are recorded as a reduction to regulatory liabilities and are not captured in Wildfire-related claims.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense decreased by $184 million, or 32%, in 2024 compared to 2023. These decreases were primarily due to less accelerated amortization of the Wildfire Fund asset and an increase in the estimated period of coverage of the Wildfire Fund from 15 to 20 years. See Note 2 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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Depreciation, Amortization, and Decommissioning

The Utility’s Depreciation, amortization, and decommissioning expenses increased by $451 million, or 12%, in 2024 compared to 2023. These increases were primarily due to the growth in plant balance from capital additions and an increase in decommissioning expense due to the reversal of approximately $175 million in accrued nuclear decommissioning expense as a result of the 2021 NDCTP final decision in 2023.

Interest Income

There was no material change to Interest income in 2024 compared to 2023.

Interest Expense

The Utility’s Interest expense increased by $296 million, or 12%, in 2024 compared to 2023. These increases were primarily due to an increase in long-term debt and higher interest rates paid on regulatory balancing accounts.

Other Income, Net

There was no material change to Other income, net in 2024 compared to 2023.

Income Tax Benefit

The Utility’s Income tax benefit decreased by $1.4 billion, or 93%, in 2024 compared to 2023. These decreases were primarily due to a decrease in the tax benefit recognized related to the Fire Victim Trust’s sale of PG&E Corporation common stock as well as higher pre-tax income in 2024 compared to 2023.

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

	2024		2023
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)	(0.8)	%	(34.4)	%
Effect of regulatory treatment of fixed asset differences (2)	(24.7)	%	(40.1)	%
Tax credits	(0.7)	%	(2.2)	%
Fire Victim Trust (3)	—	%	(80.2)	%
Other, net	1.2	%	1.1	%
Effective tax rate	(4.0)	%	(134.8)	%

(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, the Utility recognizes the deferred tax impact in the current period and records 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. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.

(3) Includes the tax effect of the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term.

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PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. 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 service. 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% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. The CPUC has granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025. The Utility is on track to comply with its authorized regulatory capital structure when the waiver terminates.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends 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. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.

Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2029. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026. As a result, PG&E Corporation expects to pay state income taxes in 2025 and 2026. See “Tax Matters” above and “Inflation Reduction Act” in Legislative and Regulatory Initiatives below for a discussion of events that could limit PG&E Corporation’s ability to use its net operating losses.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

As of December 31, 2024, PG&E Corporation and the Utility had access to approximately $6.7 billion of total liquidity comprised of $705 million of the Utility’s Cash and cash equivalents, $235 million of PG&E Corporation’s Cash and cash equivalents and $5.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

Credit ratings 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. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s credit rating remains below investment grade, the Utility generally does not receive unsecured credit from its energy procurement counterparties and it may be required to increase its collateral postings if its credit rating is downgraded.

Restrictive Debt Covenants

PG&E Corporation’s and the Utility’s credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants, including a financial covenant requiring PG&E Corporation and the Utility to maintain a total consolidated debt to total consolidated capitalization ratio of no more than 70% and 65% for PG&E Corporation and the Utility, respectively, as of the end of each fiscal quarter.

The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. PG&E Corporation’s and the Utility’s various credit agreements and the DOE Loan Guarantee Agreement contain provisions that may result in an event of default if there was a failure to meet payment terms or observe other covenants under other financing arrangements that could result in an acceleration of payments due. Such provisions are referred to as “cross-default” provisions. As of December 31, 2024, PG&E Corporation and the Utility remain in compliance with all financial covenants.

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Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of December 31, 2024, PG&E Corporation and the Utility had Cash and cash equivalents of $235 million and $705 million, respectively.

As of December 31, 2024, the Utility had contributed $911 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Financial Resources

Equity Financings

Common Stock Offering

On December 4, 2024, PG&E Corporation issued 55,961,070 shares of its common stock, no par value, for cash proceeds of $1.13 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.

For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Series A Mandatory Convertible Preferred Stock

On December 5, 2024, PG&E Corporation issued $1.6 billion of 6.000% Series A Mandatory Convertible Preferred Stock, no par value, with a dividend rate of 6.000% per annum on the liquidation preference of $50 per share (the “Mandatory Convertible Preferred Stock”) due December 2027. The Mandatory Convertible Preferred Stock dividend is payable on March 1, June 1, September 1, and December 1 of each year. The Mandatory Convertible Preferred Stock ranks senior to PG&E Corporation’s common stock with respect to the payment of dividends. The proceeds from this issuance are intended to be used for general corporate purposes which may include, among other things, to fund its five-year capital investment plan.

For more information, see Note 7 of the Notes to the Consolidated Financial Statements in Item 8.

Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, its share price, its earnings, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings.

Debt Financings

Utility

The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.

On February 28, 2024, the Utility completed the sale of (i) $850 million aggregate principal amount of 5.550% First Mortgage Bonds due 2029, (ii) $1.1 billion aggregate principal amount of 5.800% First Mortgage Bonds due 2034 and (iii) $300 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The Utility used the net proceeds for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On September 5, 2024, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of Floating Rate First Mortgage Bonds due 2025 and (ii) $750 million aggregate principal amount of 5.900% First Mortgage Bonds due 2054. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

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AB 1054 Securitization

On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of senior secured recovery bonds in three tranches: (1) approximately $300 million with an interest rate of 4.838% due June 1, 2035, (2) approximately $373 million with an interest rate of 5.231% due June 1, 2042, and (3) approximately $746 million with an interest rate of 5.529% due June 1, 2051. The $1.41 billion net proceeds were used by the Utility to reimburse itself for previously incurred fire risk mitigation capital expenditures through the repayment of a portion of loans outstanding under the Utility Revolving Credit Agreement.

For more information, see “AB 1054 Securitization” in Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation

On September 11, 2024, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes will initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes, including to prepay in full, all loans outstanding under its then-existing term loan agreement in an aggregate principal amount equal to $500 million.

On November 15, 2024, PG&E Corporation completed the sale of an additional $500 million aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes will initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes.

Facilities and Term Loans

As of December 31, 2024, PG&E Corporation and the Utility had $500 million and $3.8 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the $1.5 billion Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. 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 April 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 26, 2024, the Utility amended its existing receivables securitization program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

On June 28, 2024, the Utility amended its then-existing bridge term loan credit agreement to, among other things, (i) extend the maturity date from August 15, 2024 to December 16, 2024, and (ii) modify the mandatory prepayment provision to require the Utility to prepay term loans outstanding under such credit agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance of debt securities or incurrence of any debt under any bank credit facilities (excluding AB 1054 securitizations and the Utility’s revolving credit agreement). As of December 31, 2024, the bridge term loan was no longer outstanding.

On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

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PG&E Corporation

On July 25, 2024, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date from June 22, 2026 to June 22, 2027 (subject to a one-year extension at the option of PG&E Corporation), and (ii) remove the cash coverage ratio covenant.

For more information, see “Credit Facilities and Term Loans” in Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

Other Financings

DOE Loan Guarantee Agreement

On January 17, 2025, the Utility entered into the following agreements: (1) the DOE Loan Guarantee Agreement; (2) a note purchase agreement dated as of January 17, 2025 (the “Note Purchase Agreement”), among the Utility, the Federal Financing Bank (“FFB”), and the DOE; and (3) a future advance promissory note dated January 17, 2025, made by the Utility to FFB (the “Note” and together with the Note Purchase Agreement, the “FFB Note Documents”).

The FFB Note Documents provide for a multi-advance term loan facility (the “Facility”), under which the Utility may make quarterly term loan borrowings through FFB, subject to satisfaction of certain conditions. Proceeds of the advances under the Facility are to be used by the Utility to reimburse for “Eligible Project Costs” previously incurred and either expended or accrued by the Utility in connection with projects that DOE has determined to be “Eligible Projects” (each as defined in the DOE Loan Guarantee Agreement). The aggregate amount of advances under the Facility may not exceed $15 billion.

In connection with the DOE Loan Guarantee Agreement, the DOE agreed to guarantee the obligations of the Utility under the FFB Note Documents (the “Guaranteed Loan”). The Guaranteed Loan is made pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, as amended (the “Title XVII Loan Guarantee Program”).

The Facility permits the Utility to borrow during the “Availability Period,” which continues until the earliest of: (1) the date the Guaranteed Loan reaches $15 billion; (2) September 15, 2031; (3) the occurrence of an event that causes the guarantee issued by DOE in favor of FFB pursuant to the FFB Note Purchase Agreement to cease to be in full force and effect (“Guarantee Trigger Event”); (4) the date of termination of obligations to disburse any undisbursed amounts of the Guaranteed Loan following the occurrence of any event of default; and (5) January 17, 2030 if the initial first advance has not occurred by that date

The Utility may request advances under the Facility during the Availability Period not more than once per calendar quarter by submission of an advance request to DOE with respect to the Eligible Project(s) and Eligible Project Costs subject to such advance. The aggregate amount of advances cannot exceed $10 billion in any calendar year other than calendar year 2028, during which the aggregate amount of advances cannot exceed $5 billion.

Advances are subject to the satisfaction of customary and non-customary conditions. Such conditions include: (1) approval by DOE in its sole discretion of the Eligible Project(s) subject to such advance; (2) compliance with the requirements of the Title XVII Loan Guarantee Program; (3) certification of the ongoing accuracy in all material respects of all representations and warranties; (4) evidence of compliance with the Davis-Bacon Act of 1931, as amended; (5) compliance with the Cargo Preference Act of 1954, as amended; (6) confirmation that the Utility’s long-term senior secured credit ratings are at least investment grade; (7) completion of the environmental review process pursuant to the National Environmental Policy Act, as amended, with respect to the Eligible Project(s) subject to such advance; and (8) other documentary conditions required by the DOE Loan Guarantee Agreement and the FFB Note Documents.

The final maturity date for each advance under the Facility will be the earlier of the interest payment date following the 22nd anniversary of the date of such advance or January 17, 2055.

As of the date of this report, the Utility has not borrowed any advances under the Facility. The Utility is not able to predict the timing or amount of any funds it may receive from the Facility in the future as a result of the January 20, 2025 executive order by President Trump entitled “Unleashing American Energy” regarding funds authorized by the Inflation Reduction Act.

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Citizens Energy Corporation

On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. The transactions contemplated by the agreement are subject to FERC and CPUC approval.

Dividends

Utility

On each of February 13, May 16, and September 19, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on May 15, August 15, and November 15, 2024, respectively, to holders of record as of April 30, July 31, and October 31, 2024. On November 29, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on February 15, 2025, to holders of record as of January 31, 2025.

On each of February 13, May 16, September 19, and November 29, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million, $500 million, $500 million, and $575 million, which were paid to PG&E Corporation on March 25, June 3, September 20, and December 24, 2024. respectively.

PG&E Corporation

On each of February 13, May 16, and September 19, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, each declaration totaling $21 million, which were paid on April 15, July 15, and October 15, 2024, to holders of record as of March 28, June 28 and September 30, 2024, respectively. On November 29, 2024, the Board of Directors of PG&E Corporation declared a new quarterly common stock dividend of $0.025 per share, totaling $55 million, which was paid on January 15, 2025, to holders of record as of December 31, 2024.

In December 2024, PG&E Corporation announced a new dividend policy entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions determined by the Board may be impacted by earnings, cash flows, credit metrics and other business conditions.

On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share, to be payable on March 1, 2025, to holders of record as of February 14, 2025.

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 2024 and 2023.

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2024		2023
Net cash provided by operating activities	$	8,268	$	5,097
Net cash used in investing activities	(11,375)		(9,162)
Net cash provided by financing activities	3,348		3,979
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	241	$	(86)

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Operating Activities

Net cash provided by operating activities increased by $3.2 billion, or 62%, in 2024 compared to 2023. The increases were primarily due to:

•an increase in collections through rates including as a result of the 2023 GRC final decision; and

•decrease in amounts paid for natural gas due to a decrease in natural gas commodity prices.

Partially offset by:

•an increase in climate credits issued to customers; and

•lower cash return for collateral posted in 2024 due to a decrease in the volatility of gas prices.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base and from cost recovery applications (see “Cost Recovery Proceedings” below for more information).

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 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 amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8);

•the timing and amount of costs in connection with the 2023-2025 WMP and the portion of the costs previously incurred in connection with the 2020-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

•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; and

•the timing and amount of electric commodity price volatility and differences between commodity costs and revenue collections.

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

Investing Activities

The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2024, compared to December 31, 2023.

(in millions)	Year Ended December 31,
Cash used in investing activities - 2023	$	(9,162)
Capital expenditures	(655)
Net purchases related to customer credit trust investments	(677)
Purchases of self-insurance investments	(898)
Other investing activities	17
Net increase in cash used in investing activities	(2,213)
Cash used in investing activities - 2024	$	(11,375)

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Net cash used in investing activities increased by $2.2 billion, or 24%, in 2024 compared to 2023. The increases were primarily due to a $898 million increase in purchases of self-insurance investments in 2024, and a $677 million increase in net purchases of customer credit trust investments, net of proceeds from sales. In addition, capital expenditures increased by $655 million in 2024 compared to 2023 primarily due to increased customer connection energization and electric distribution pole replacement.

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, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance 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.

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 $12.9 billion of capital expenditures in 2025. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the self-insurance captive (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $650 million to be contributed by March 2025 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8).

Financing Activities

The following table summarizes changes in key components of the Utility’s financing cash flows for the year ended December 31, 2024, compared to December 31, 2023.

(in millions)	Year Ended December 31,
Cash provided by financing activities - 2023	$	3,979
Net borrowings under credit facilities	(3,384)
Repayments under term loan credit facilities	(4,200)
Issuance of long-term debt	(2,484)
Issuance of short-term debt	999
Repayments of long-term debt	2,275
Proceeds from issuance of senior secured recovery bonds in AB 1054	1,409
Proceeds related to DWR loans	980
Equity contribution from PG&E Corporation	4,070
Other financing activities	(296)
Net increase in cash provided by financing activities	(631)
Cash provided by financing activities - 2024	$	3,348

Net cash provided by financing activities decreased by $631 million, or 16%, in 2024 compared to 2023. The decreases were primarily due to:

•$4.2 billion increase in net repayments under term loan credit facilities; and

•$3.4 billion decrease in net borrowings under credit facilities.

Partially offset by:

•$4.1 billion increase in equity contributions from PG&E Corporation;

•$1.4 billion in proceeds related to the issuance of senior secured recovery bonds in the AB 1054 securitization, with no similar transaction in 2023;

•$999 million in proceeds related to issuance of short-term debt, with no similar transaction in 2023; and

•$980 million in proceeds related to the DWR loan in 2024, with no similar transaction in 2023.

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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 the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation. As of December 31, 2024, PG&E Corporation has completed the planned equity financing for its $63 billion 2024 through 2028 capital expenditure plan.

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 Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and in “Regulatory Matters” below 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.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, 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. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following proceedings.

During the year ended December 31, 2024 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

•In December 2024, the CPUC issued a final decision in the 2021 WMCE proceeding approving a revenue requirement of $429 million associated with costs recorded to the VMBA.

•In December 2024, the CPUC issued a final decision approving $723 million out of the Utility’s request of $761 million for net recovery of the Utility’s costs to operate DCPP from 2023 through 2025.

•In November 2024, the OEIS issued a final decision approving the Utility’s 2025 WMP update, which the CPUC ratified on January 16, 2025. The OEIS issued a safety certificate for the Utility on December 11, 2024.

•In October 2024, the CPUC issued a final decision in the Utility’s 2023 Cost of Capital proceeding that changed the cost of capital adjustment mechanism and set the Utility’s ROE at 10.28% effective January 1, 2025.

•In September 2024, the CPUC issued a final decision on interim rate recovery in the Utility’s 2023 WMCE that grants the Utility interim rate relief of $944 million, plus interest, subject to refund.

•In August 2024, the FERC issued an order approving the Utility’s TO18 transmission rate case settlement.

•In July 2024, the CPUC issued a final decision for Phase 2 of the GRC that set a cumulative expenditure cap at $2.26 billion for the period of 2024 to 2026 and permits the Utility to revisit the 2025 and 2026 cap amounts.

•In March 2024, the CPUC granted the Utility’s request to delay $650 million of contributions to the customer credit trust from 2024 to 2025.

•In March 2024, the CPUC approved a final decision in the WGSC proceeding authorizing the Utility to recover $516 million in interim rates to be recovered over 12 months starting April 1, 2024.

•In February 2024, the CPUC issued a final resolution approving an Administrative Consent Order and Agreement between the SED and the Utility regarding the 2021 Dixie fire.

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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 proceedings. For instance, 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 later 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 on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than 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 of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2024, the Utility had recorded an aggregate amount of approximately $3.6 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $2.4 billion was accounted for as long term as of December 31, 2024. See Note 3 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.

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery 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, 2024 are summarized in the following table:

Proceeding	Request (1)	Status
2021 WMCE	Revenue requirement of approximately $1.47 billion	Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. Decision authorizing $429 million of revenue requirement for the VMBA related costs adopted December 2024.
2022 WMCE	Revenue requirement of approximately $1.29 billion	Filed December 2022. Decision authorizing $1.1 billion of interim rate relief adopted June 2023. Partial settlement filed December 2023.
2023 WMCE	Revenue requirement of approximately $1.86 billion	Application filed December 2023. Decision authorizing $944 million of interim rate relief adopted September 2024.
2024 WMCE	Revenue requirement of approximately $435 million	Application filed November 2024.
2023 WGSC	Revenue requirement of approximately $688 million	Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024.

(1) The revenue requirement request amounts do not include interest.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

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.

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The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. 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 August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023. The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA.

On December 27, 2024, the CPUC issued a final decision approving a revenue requirement of $429 million associated with costs recorded to the VMBA. On January 27, 2025, the Utility filed an application for rehearing.

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.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

On December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.

On December 19, 2024, the CPUC extended the statutory deadline to resolve the remaining issues in the proceeding to September 30, 2025.

2023 WMCE Application

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 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 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

On September 16, 2024, the CPUC issued a final decision on interim rate recovery that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

The CPUC’s procedural schedule indicates a final decision by the second quarter of 2025.

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2024 WMCE Application

On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in this application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023.

The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in CEMA.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:

(in millions)	Recorded Costs
WMPMA	$	2,095
FRMMA	165
Gas storage balancing account	101
In line inspection memorandum account	92
Other	45
Total	$	2,498

In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024.

The administrative law judge has adopted a schedule that would result in a proposed decision on the wildfire mitigation costs in the first half of 2025 and a final decision on the gas safety and electric modernization costs by June 2025.

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. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS approves guidelines. See “SB 884 10-Year Distribution Undergrounding Program” below.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on 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 risks associated with the lower level of work achieved compared to that funded by the CPUC.

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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, 2024 are summarized in the following table:

Rate Case	Request	Status
2023 GRC	Phase 2: balancing account for additional energization costs	Final decision on Phase 2 issued July 2024 sets a cumulative expenditure cap at $2.26 billion for the period of 2024 to 2026.
2023 Cost of Capital, Phase 2	Maintain cost of capital adjustment mechanism	Final decision issued October 2024, changing the cost of capital adjustment mechanism and setting the Utility’s ROE at 10.28% effective January 1, 2025.
TO18, TO19, and TO20	See Note 15 of the Notes to the Consolidated Financial Statements in Item 8	Settlement approved by the FERC August 2024.
TO21	Revenue requirement of $2.78 billion for 2024	Accepted December 2023, except as to CAISO adder. Settlement in principle reached December 2024. Appeal of FERC’s order regarding CAISO adder filed June 2024 and remains pending.

2023 General Rate Case

Phase 1

On November 17, 2023, the CPUC issued a final decision on Phase 1.

The Utility is authorized to collect through rates the approved revenue requirement increases beginning January 1, 2024 and to amortize the incremental revenue increases related to 2023 for 24 months over the period of January 1, 2024 through December 31, 2025.

The final decision authorized the following:

Year	Revenue Requirement (in billions)		Rate Base (in billions)
2023	$	13.52	$	45.8
2024	14.24		48.8
2025	14.60		51.2
2026	14.80		54.0

For more information, see “Regulatory Matters” in the 2023 Form 10-K.

Phase 2 and Energization Timelines Order Instituting Rulemaking

On September 15, 2023, the Utility served opening testimony proposing to recover energization costs incremental to the forecasts of the Utility’s Phase 1 2023 GRC. Energization activities include new business connections and capacity-related work to allow for the connections and reduce energization timelines. On July 16, 2024, the CPUC issued a final decision approving a memorandum account with interim rate relief, subject to annual caps and reasonableness review in the 2027 GRC application. The overall expenditure cap was set at $2.26 billion for the period of 2024 to 2026. The decision also provides the Utility the ability to request revisions to the 2025 and 2026 cap amounts under certain conditions. On October 4, 2024, the Utility filed a motion to increase the 2025 and 2026 cap amounts by an aggregate $3.1 billion, which reflects approximately $300 million originally included in 2024, for a net increase of $2.8 billion.

On October 18, 2024, the assigned commissioner issued an amended scoping memo providing for a final decision in spring 2025.

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Cost of Capital Proceedings

2023 Cost of Capital Application

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital, ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On October 22, 2024, the CPUC issued the decision in Phase 2 modifying the Cost of Capital mechanism and setting new returns on equity effective January 1, 2025.

On November 6, 2024, the Utility submitted an advice letter with updated 2025 cost of capital rates. On December 4, 2024, the CPUC approved the advice letter and the following cost of capital rates, which went into effect beginning January 1, 2025:

	Cost		Weight	Weighted Cost
Return on Common Equity	10.28	%	52.00%	5.35%
Return on Preferred Equity	5.52	%	0.50%	0.03%
Return on Long-term debt	4.80	%	47.50%	2.28%

The Utility will file the next cost of capital application on March 20, 2025 for test year 2026.

Transmission Owner Rate Cases

Transmission Owner Rate Case for 2024 (the “TO21” rate case)

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasted a 2024 retail electric transmission revenue requirement of $2.83 billion. The proposed amount reflects an approximately 11% decrease over the rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above). The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. The Utility requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO. The TO21 filing also addresses the Utility’s capital structure and several new issues including wildfire self-insurance recovery from transmission customers.

On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but denying the 0.5% ROE adder for participation in the CAISO, which results in a forecast transmission revenue requirement of $2.78 billion. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO. On June 12, 2024, the FERC issued an order denying the Utility’s request for rehearing. On June 18, 2024, the Utility and California IOUs filed an appeal of the FERC’s order denying the Utility’s request for rehearing. The utilities’ joint opening brief was filed on September 11, 2024 and reply brief was filed on December 17, 2024.

On December 18, 2024, the settlement judge issued a status report to the FERC stating that the Utility and the other parties have reached a settlement in principle on all issues in the TO21 rate case. The parties will draft an offer of settlement to be filed with the FERC for approval.

Other Regulatory Proceedings

2023-2025 Wildfire Mitigation Plan

On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events. On December 29, 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP. On February 15, 2024, the CPUC ratified the OEIS’s approval. On January 8, 2024, the Utility filed a change order request to update some of the forecasted work in the WMP for 2024. On May 31, 2024, the OEIS issued a decision approving in part and denying in part the change order request.

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The Utility submitted an updated 2025 WMP on April 2, 2024, as directed by the OEIS. On November 19, 2024, the OEIS issued a final approval of the Utility’s 2025 WMP update. On January 16, 2025, the CPUC ratified the OEIS’s approval.

Extension of Diablo Canyon Operations

On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at DCPP through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility continues to operate DCPP on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs are responsible for the cost of extended operations.

The key steps to continued operations are NRC license renewal and approvals from California state agencies, including the CPUC, CEC, California State Lands Commission, California Coastal Commission, and other state agencies. As set forth below, many of these approvals have been received.

On February 28, 2023, and in consultation with the CAISO and CPUC, the CEC determined that it is prudent to extend the operation of DCPP to support electric system reliability through 2030.

The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with DCPP. On June 5, 2023, the California State Lands Commission approved an extension of the Utility’s lease at DCPP through October 31, 2030.

On August 15, 2023, the California State Water Resources Control Board approved the Utility’s plan for once-through cooling at DCPP.

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On December 19, 2023, the NRC deemed the application sufficient, which allows continued operations at DCPP past the plant’s current licenses until the relicensing review is complete. The NRC’s schedule indicates that it will issue a final safety evaluation report and supplemental environmental impact statement by June 2025.

On December 14, 2023, the CPUC approved extended operations at DCPP until October 31, 2029 for Unit 1 and October 31, 2030 for Unit 2. The approval is subject to the following conditions: (1) the NRC continues to authorize DCPP operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that DCPP extended operations are imprudent or unreasonable.

On May 3, 2024, the CEC issued a report concluding that no suitable supply-side resources can be brought online as alternatives to DCPP’s energy and capacity output prior to the planned retirement dates in 2024 and 2025.

On December 19, 2024, the CPUC issued a final decision. As a result, the Utility will recover $711 million through rates (compared to its request of $761 million) for net recovery of its costs to operate DCPP from 2023 through 2025.

SB 884 10-Year Distribution Undergrounding Program

On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs.

The OEIS issued draft guidelines on May 8, 2024, revised guidelines on September 10, 2024, and second revised guidelines on January 7, 2025.

The Utility expects to submit its undergrounding plan to the OEIS after final guidelines are issued before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

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LEGISLATIVE AND REGULATORY INITIATIVES

Inflation Reduction Act

In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the 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 qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility expect to pay corporate alternative minimum tax beginning in 2027, the amount of which may become substantial in future years. As of December 31, 2024, the law did not have a material impact on the PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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 15 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 does not have a balancing account for costs in excess of its revenue requirement for natural gas transportation and storage service to non-core customers. 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. PG&E Corporation uses value-at-risk to measure its shareholders’ exposure to these risks. The value-at-risk was approximately $5 million and $4 million at December 31, 2024 and 2023, respectively. See Note 10 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, 2024 and 2023, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $6 million and $57 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

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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, 2024	$	1,114	4	$	708
December 31, 2023	$	926	3	$	457

(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 at least $21 billion through (i) a 15-year non-bypassable 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. In December 2023 and 2024, the Utility made its fifth and sixth annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2024, the Utility has four remaining annual contributions of $193 million (based on the 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, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $564 million in Other noncurrent liabilities, $301 million in Current assets - Wildfire Fund asset, and $4.1 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2024 and 2023, the Utility recorded amortization and accretion expense of $383 million and $567 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 20 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, 2024, 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 five years assuming less effectiveness.

Other assumptions used to estimate the useful life include the disclosed 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 re-evaluate the estimated period of coverage annually and when additional information becomes available, 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 its individual contribution amount. 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’ service areas 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. PG&E Corporation and the Utility recorded $72 million and $102 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2024 and 2023, respectively. As of December 31, 2024, PG&E Corporation and the Utility recorded $600 million and $156 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 2 and “Wildfire Fund under AB 1054” in Note 14 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.

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 14 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 outside counsel costs, which are expensed as incurred. Actual results may differ materially from these estimates and assumptions. See Note 14 and Note 15 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 arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss, 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, communications with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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.

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The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has 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, which could affect the cost of the remediation effort.

As of December 31, 2024 and 2023, 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. The Utility continues to apply ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2024, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $23.8 billion.

Determining probability requires significant judgment by management and includes consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or 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.

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 MGMA 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 RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC.

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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 customer harm threshold (“CHT”). SB 901 required the CPUC to establish the CHT 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. 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, 2024, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

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

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.

At December 31, 2024, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.4 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 3 of the Notes to the Consolidated Financial Statements in Item 8.

The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate, and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.

87

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 2025 was 7.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2033 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 6.4% compares to a ten-year actual return of 5.1%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 858 Aa-grade non-callable bonds at December 31, 2024. 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 2024 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2024
Discount rate	(0.50)	%	$	(1)	$	1,093
Rate of return on plan assets	(0.50)	%	85		—
Rate of increase in compensation	0.50	%	30		250

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 2024 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2024
Health care cost trend rate	0.50	%	$	6	$	37
Discount rate	(0.50)	%	6		78
Rate of return on plan assets	(0.50)	%	12		—

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 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 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.

88

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2024		2023		2022
Operating Revenues
Electric	$	17,811	$	17,424	$	15,060
Natural gas	6,608		7,004		6,620
Total operating revenues	24,419		24,428		21,680
Operating Expenses
Cost of electricity	2,261		2,443		2,756
Cost of natural gas	1,192		1,754		2,100
Operating and maintenance	11,808		11,924		9,809
SB 901 securitization charges, net	33		1,267		608
Wildfire-related claims, net of recoveries	94		64		237
Wildfire Fund expense	383		567		477
Depreciation, amortization, and decommissioning	4,189		3,738		3,856
Total operating expenses	19,960		21,757		19,843
Operating Income	4,459		2,671		1,837
Interest income	604		606		162
Interest expense	(3,051)		(2,850)		(1,917)
Other income, net	300		272		394
Income Before Income Taxes	2,312		699		476
Income tax benefit	(200)		(1,557)		(1,338)
Net Income	2,512		2,256		1,814
Preferred stock dividend requirement	37		14		14
Income Available for Common Shareholders	$	2,475	$	2,242	$	1,800
Weighted Average Common Shares Outstanding, Basic	2,141		2,064		1,987
Weighted Average Common Shares Outstanding, Diluted	2,147		2,138		2,132
Net Income Per Common Share, Basic	$	1.16	$	1.09	$	0.91
Net Income Per Common Share, Diluted	$	1.15	$	1.05	$	0.84

See accompanying Notes to the Consolidated Financial Statements.

89

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2024		2023		2022
Net Income	$	2,512	$	2,256	$	1,814
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)		(16)		21
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $3, and $3, respectively)	1		8		(6)
Total other comprehensive income (loss)	(6)		(8)		15
Comprehensive Income	2,506		2,248		1,829
Preferred stock dividend requirement of subsidiary	37		14		14
Comprehensive Income Attributable to Common Shareholders	$	2,469	$	2,234	$	1,815

See accompanying Notes to the Consolidated Financial Statements.

90

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at
	December 31, 2024		December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents	$	940	$	635
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	273		297
Accounts receivable
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220		2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487		1,254
Regulatory balancing accounts	7,227		5,660
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	1,810		1,494
Regulatory assets	234		300
Inventories
Gas stored underground and fuel oil	52		65
Materials and supplies	768		805
Wildfire Fund asset	301		450
Wildfire self-insurance asset	905		—
Other	999		1,375
Total current assets	17,216		14,383
Property, Plant, and Equipment
Electric	86,639		80,345
Gas	31,623		29,830
Construction work in progress	4,458		4,452
Financing lease ROU asset and other	814		787
Total property, plant, and equipment	123,534		115,414
Accumulated depreciation	(35,305)		(33,093)
Net property, plant, and equipment	88,229		82,321
Other Noncurrent Assets
Regulatory assets	15,561		17,189
Customer credit trust	377		233
Nuclear decommissioning trusts	3,833		3,574
Operating lease ROU asset	524		598
Wildfire Fund asset	4,070		4,297
Income taxes receivable	1		24
Other (includes noncurrent accounts receivable of $82 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $18 million and $0 at respective dates)	3,849		3,079
Total other noncurrent assets	28,215		28,994
TOTAL ASSETS	$	133,660	$	125,698

See accompanying Notes to the Consolidated Financial Statements.

91

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at
	December 31, 2024		December 31, 2023
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,523	$	3,971
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146		1,376
Accounts payable
Trade creditors	2,748		2,309
Regulatory balancing accounts	3,169		1,669
Other	748		851
Operating lease liabilities	85		80
Financing lease liabilities	577		259
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	760		679
Wildfire-related claims	916		1,422
Other	3,658		4,698
Total current liabilities	16,330		17,314
Noncurrent Liabilities
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	53,569		50,975
Regulatory liabilities	19,417		19,444
Pension and other postretirement benefits	808		476
Asset retirement obligations	5,444		5,512
Deferred income taxes	3,082		1,980
Operating lease liabilities	439		518
Financing lease liabilities	4		554
Other	4,166		3,633
Total noncurrent liabilities	86,929		83,092
Equity
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		—
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,193,573,536 and 2,133,597,758 shares outstanding at respective dates	31,555		30,374
Reinvested earnings	(2,966)		(5,321)
Accumulated other comprehensive loss	(19)		(13)
Total shareholders’ equity	30,149		25,040
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	30,401		25,292
TOTAL LIABILITIES AND EQUITY	$	133,660	$	125,698

See accompanying Notes to the Consolidated Financial Statements.

92

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	2,512	$	2,256	$	1,814
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,189		3,738		3,856
Bad debt expense	341		636		143
Allowance for equity funds used during construction	(184)		(179)		(184)
Deferred income taxes and tax credits, net	1,098		(765)		(452)
Wildfire Fund expense	383		568		477
Disallowed capital expenditures	—		—		15
Other	310		(116)		517
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,061)		(369)		(757)
Wildfire-related insurance receivable	318		358		453
Inventories	45		(28)		(246)
Accounts payable	30		(90)		627
Wildfire-related claims	(506)		(489)		(810)
Other current assets and liabilities	(231)		397		17
Regulatory assets, liabilities, and balancing accounts, net	1,545		(429)		(1,131)
Contributions to Wildfire Fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(561)		(548)		(425)
Net cash provided by operating activities	8,035		4,747		3,721
Cash Flows from Investing Activities
Capital expenditures	(10,369)		(9,714)		(9,584)
Proceeds from sales and maturities of nuclear decommissioning trust    investments	1,980		2,235		3,316
Purchases of nuclear decommissioning trust investments	(2,002)		(2,252)		(3,208)
Proceeds from sales and maturities of customer credit trust investments	398		556		250
Purchases of customer credit trust investments	(519)		—		(1,022)
Purchases of self-insurance investments	(898)		—		—
Other	35		13		34
Net cash used in investing activities	(11,375)		(9,162)		(10,214)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,873		10,675		10,130
Repayments under credit facilities	(10,122)		(10,540)		(9,750)
Borrowings under term loan credit facilities	—		2,100		—
Repayments under term loan credit facilities	(2,600)		(2,181)		—
Short-term borrowings, net of issuance costs of $1, $0, and $0 at    respective dates	999		—		—
Short-term debt matured	—		—		(300)
Proceeds from issuance of long-term debt, net of premium, discount and    issuance costs of $5, $67, and $29 at respective dates	4,495		5,483		4,271
Repayment of long-term debt	(800)		(3,075)		(5,968)

93

Proceeds from issuance of SB 901 recovery bonds, net of financing fees    of $0, $0 and $36 at respective dates	—		—		7,464
Repayment of SB 901 recovery bonds	(129)		(130)		(33)
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees    of $10, $0 and $11 at respective dates	1,409		—		972
Repayment of AB 1054 recovery bonds	(46)		(38)		(18)
Proceeds from DWR loan	980		—		312
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates	—		2,123		—
Mandatory convertible preferred stock issued	1,579		—		—
Common stock issued	1,128		—		—
Common stock dividends paid	(86)		—		—
Other	(59)		(17)		53
Net cash provided by financing activities	3,621		4,400		7,133
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	281		(15)		640
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	932		947		307
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	1,213	$	932	$	947
Less: Restricted cash and restricted cash equivalents	(273)		(297)		(213)
Cash and cash equivalents at December 31	$	940	$	635	$	734

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(2,421)	$	(2,286)	$	(1,607)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,144	$	1,105	$	1,174
Operating lease liabilities arising from obtaining ROU assets	6		269		529
Financing lease liabilities arising from obtaining ROU assets	43		52		—
Reclassification of operating lease liabilities to financing lease liabilities	—		913		—
DWR loan forgiveness and performance-based disbursements	192		214		—
Changes to PG&E Corporation common stock and treasury stock in    connection with share exchanges with the Fire Victim Trust	—		(2,517)		(2,337)
Common stock dividends declared but not yet paid	55		21		—
Mandatory convertible preferred stock dividends declared but not yet paid	23		—		—

See accompanying Notes to the Consolidated Financial Statements.

94

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Preferred Stock		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, 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
Net income	—		—	—		—	—		2,256		—		2,256		—		2,256
Other comprehensive loss	—		—	—		—	—		—		(8)		(8)		—		(8)
Common stock issued, net	—		145,812,810	(2,517)		—	—		—		—		(2,517)		—		(2,517)
Treasury stock disposition	—		—	—		(247,743,590)	2,517		—		—		2,517		—		2,517
Stock-based compensation amortization	—		—	4		—	—		—		—		4		—		4
Common stock dividends declared	—		—	—		—	—		(21)		—		(21)		—		(21)
Preferred stock dividend requirement of subsidiary	—		—	—		—	—		(14)		—		(14)		—		(14)
Balance at December 31, 2023	$	—	2,133,597,758	$	30,374	—	$	—	$	(5,321)	$	(13)	$	25,040	$	252	$	25,292
Net income	—		—	—		—	—		2,512		—		2,512		—		2,512
Other comprehensive loss	—		—	—		—	—		—		(6)		(6)		—		(6)
Preferred Stock issued, net	1,579		—	—		—	—		—		—		1,579		—		1,579
Common stock issued, net	—		59,975,778	1,128		—	—		—		—		1,128		—		1,128
Stock-based compensation amortization	—		—	53		—	—		—		—		53		—		53
Common stock dividends declared	—		—	—		—	—		(120)		—		(120)		—		(120)
Preferred stock dividend requirement	—		—	—		—	—		(37)		—		(37)		—		(37)
Balance at December 31, 2024	$	1,579	2,193,573,536	$	31,555	—	$	—	$	(2,966)	$	(19)	$	30,149	$	252	$	30,401

See accompanying Notes to the Consolidated Financial Statements.

95

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2024		2023		2022
Operating Revenues
Electric	$	17,811	$	17,424	$	15,060
Natural gas	6,608		7,004		6,620
Total operating revenues	24,419		24,428		21,680
Operating Expenses
Cost of electricity	2,261		2,443		2,756
Cost of natural gas	1,192		1,754		2,100
Operating and maintenance	11,787		11,913		9,725
SB 901 securitization charges, net	33		1,267		608
Wildfire-related claims, net of recoveries	94		64		237
Wildfire Fund expense	383		567		477
Depreciation, amortization, and decommissioning	4,189		3,738		3,856
Total operating expenses	19,939		21,746		19,759
Operating Income	4,480		2,682		1,921
Interest income	589		593		162
Interest expense	(2,781)		(2,485)		(1,658)
Other income, net	319		293		595
Income Before Income Taxes	2,607		1,083		1,020
Income tax benefit	(105)		(1,461)		(1,206)
Net Income	2,712		2,544		2,226
Preferred stock dividend requirement	14		14		14
Income Available for Common Stock	$	2,698	$	2,530	$	2,212

See accompanying Notes to the Consolidated Financial Statements.

96

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2024		2023		2022
Net Income	$	2,712	$	2,544	$	2,226
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $5, and $2, at respective dates)	(8)		(12)		6
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $4, and $3, respectively)	1		7		(5)
Total other comprehensive income (loss)	(7)		(5)		1
Comprehensive Income	$	2,705	$	2,539	$	2,227

See accompanying Notes to the Consolidated Financial Statements.

97

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at
	December 31, 2024		December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents	$	705	$	442
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	272		294
Accounts receivable
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220		2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487		1,254
Regulatory balancing accounts	7,227		5,660
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	1,810		1,495
Regulatory assets	234		300
Inventories
Gas stored underground and fuel oil	52		65
Materials and supplies	768		805
Wildfire Fund asset	301		450
Wildfire self-insurance asset	905		—
Other	998		1,374
Total current assets	16,979		14,187
Property, Plant, and Equipment
Electric	86,639		80,345
Gas	31,623		29,830
Construction work in progress	4,458		4,452
Financing lease ROU asset and other	814		787
Total property, plant, and equipment	123,534		115,414
Accumulated depreciation	(35,304)		(33,093)
Net property, plant, and equipment	88,230		82,321
Other Noncurrent Assets
Regulatory assets	15,561		17,189
Customer credit trust	377		233
Nuclear decommissioning trusts	3,833		3,574
Operating lease ROU asset	519		598
Wildfire Fund asset	4,070		4,297
Income taxes receivable	—		22
Other (includes noncurrent accounts receivable of $82 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $18 million and $0 at respective dates)	3,697		2,934
Total other noncurrent assets	28,057		28,847
TOTAL ASSETS	$	133,266	$	125,355

See accompanying Notes to the Consolidated Financial Statements.

98

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at
	December 31, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	1,523	$	3,971
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146		1,376
Accounts payable
Trade creditors	2,745		2,307
Regulatory balancing accounts	3,169		1,669
Other	729		820
Operating lease liabilities	85		80
Financing lease liabilities	577		259
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	667		621
Wildfire-related claims	916		1,422
Other	3,331		4,391
Total current liabilities	15,888		16,916
Noncurrent Liabilities
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	47,958		46,376
Regulatory liabilities	19,417		19,444
Pension and other postretirement benefits	741		405
Asset retirement obligations	5,444		5,512
Deferred income taxes	3,632		2,436
Operating lease liabilities	434		518
Financing lease liabilities	4		554
Other	4,198		3,670
Total noncurrent liabilities	81,828		78,915
Shareholders’ Equity
Preferred stock	258		258
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates	1,322		1,322
Additional paid-in capital	35,930		30,570
Reinvested earnings	(1,940)		(2,613)
Accumulated other comprehensive loss	(20)		(13)
Total shareholders’ equity	35,550		29,524
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	133,266	$	125,355

See accompanying Notes to the Consolidated Financial Statements.

99

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	2,712	$	2,544	$	2,226
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,189		3,738		3,856
Bad debt expense	341		636		143
Allowance for equity funds used during construction	(184)		(179)		(184)
Deferred income taxes and tax credits, net	1,195		(663)		(319)
Wildfire Fund expense	383		568		477
Disallowed capital expenditures	—		—		15
Other	233		(176)		102
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,060)		(361)		(763)
Wildfire-related insurance receivable	318		358		453
Inventories	45		(28)		(246)
Accounts payable	44		(90)		627
Wildfire-related claims	(506)		(489)		(810)
Other current assets and liabilities	(235)		402		16
Regulatory assets, liabilities, and balancing accounts, net	1,545		(429)		(1,131)
Contributions to Wildfire Fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(559)		(541)		(438)
Net cash provided by operating activities	8,268		5,097		3,831
Cash Flows from Investing Activities
Capital expenditures	(10,369)		(9,714)		(9,584)
Proceeds from sales and maturities of nuclear decommissioning trust    investments	1,980		2,235		3,316
Purchases of nuclear decommissioning trust investments	(2,002)		(2,252)		(3,208)
Proceeds from sales and maturities of customer credit trust investments	398		556		250
Purchases of customer credit trust investments	(519)		—		(1,022)
Proceeds from intercompany note to PG&E Corporation	—		—		145
Purchases of self-insurance investments	(898)		—		—
Other	35		13		34
Net cash used in investing activities	(11,375)		(9,162)		(10,069)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,873		10,675		10,130
Repayments under credit facilities	(10,122)		(10,540)		(9,750)

100

Borrowings under term loan credit facilities	—		2,100		—
Repayments under term loan credit facilities	(2,100)		—		—
Short-term borrowings, net of issuance costs of $1, $0, and $0 at respective dates	999		—		—
Short-term debt matured	—		—		(300)
Proceeds from issuance of long-term debt, net of premium, discount and    issuance costs of $1, $67, and $29 at respective dates	2,999		5,483		4,271
Repayment of long-term debt	(800)		(3,075)		(5,941)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees    of $0, $0 and $36 at respective dates	—		—		7,464
Repayment of SB 901 recovery bonds	(129)		(130)		(33)
Proceeds from AB 1054 recovery bonds, net issuance costs of $10, $0,    and $11 at respective dates	1,409		—		972
Repayment of AB 1054 recovery bonds	(46)		(38)		(18)
Proceeds from DWR loan	980		—		312
Preferred stock dividends paid	(14)		(14)		(70)
Common stock dividends paid	(2,025)		(1,775)		(1,275)
Equity contribution from PG&E Corporation	5,360		1,290		994
Other	(36)		3		123
Net cash provided by financing activities	3,348		3,979		6,879
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	241		(86)		641
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	736		822		181
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	977	$	736	$	822
Less: Restricted cash and restricted cash equivalents	(272)		(294)		(213)
Cash and cash equivalents at December 31	$	705	$	442	$	609

 

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(2,206)	$	(1,977)	$	(1,374)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,144	$	1,105	$	1,174
Operating lease liabilities arising from obtaining ROU assets	1		269		529
Financing lease liabilities arising from obtaining ROU assets	43		52		—
Reclassification of operating lease liabilities to financing lease liabilities	—		913		—
DWR loan forgiveness and performance-based disbursements	192		214		—

 See accompanying Notes to the Consolidated Financial Statements.

101

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, 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
Net income	—		—		—		2,544		—		2,544
Other comprehensive loss	—		—		—		—		(5)		(5)
Equity contribution	—		—		1,290		—		—		1,290
Preferred stock dividend requirement	—		—		—		(14)		—		(14)
Common stock dividend	—		—		—		(1,775)		—		(1,775)
Balance at December 31, 2023	$	258	$	1,322	$	30,570	$	(2,613)	$	(13)	$	29,524
Net income	—		—		—		2,712		—		2,712
Other comprehensive income	—		—		—		—		(7)		(7)
Equity contribution	—		—		5,360		—		—		5,360
Preferred stock dividend requirement	—		—		—		(14)		—		(14)
Common stock dividend	—		—		—		(2,025)		—		(2,025)
Balance at December 31, 2024	$	258	$	1,322	$	35,930	$	(1,940)	$	(20)	$	35,550

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: 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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Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the chief operating decision maker uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.

Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2024 and 2023, the Utility also held $272 million and $294 million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

As of December 31, 2024, the Utility had contributed $911 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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 through 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.

104

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

	Year Ended December 31,
(in millions)	2024		2023		2022
Electric
Revenue from contracts with customers
Residential	$	7,504	$	6,041	$	6,130
Commercial	7,201		5,643		5,416
Industrial	2,065		1,784		1,626
Agricultural	1,815		1,413		1,830
Public street and highway lighting	103		83		77
Other, net (1)	(47)		136		(247)
Total revenue from contracts with customers - electric	18,641		15,100		14,832
Regulatory balancing accounts (2)	(830)		2,324		228
Total electric operating revenue	$	17,811	$	17,424	$	15,060
Natural gas
Revenue from contracts with customers
Residential	$	3,089	$	3,686	$	3,353
Commercial	984		1,052		1,005
Transportation service only	1,815		1,603		1,534
Other, net (1)	159		(145)		163
Total revenue from contracts with customers - gas	6,047		6,196		6,055
Regulatory balancing accounts (2)	561		808		565
Total natural gas operating revenue	6,608		7,004		6,620
Total operating revenues	$	24,419	$	24,428	$	21,680

(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 alternative 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, 2024, 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.

Expected credit losses of $341 million, $636 million, and $143 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2024, 2023, and 2022, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively. As of December 31, 2023, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $507 million and $78 million, respectively. The RUBA current balancing account balance decreased from December 31, 2023 to December 31, 2024 primarily due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

105

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. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. 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, 2024, 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 for use 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 allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” 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)	2024		2023
Electricity generating facilities (1)	1 to 75	$	11,420	$	11,423
Electricity distribution facilities	10 to 70	49,821		45,205
Electricity transmission facilities	15 to 75	18,481		17,562
Natural gas distribution facilities	15 to 60	17,213		16,324
Natural gas transmission and storage facilities	15 to 68	11,117		10,496
General plant and other	5 to 50	10,210		9,165
Financing lease		814		787
Construction work in progress		4,458		4,452
Total property, plant, and equipment		123,534		115,414
Accumulated depreciation		(35,304)		(33,093)
Net property, plant, and equipment (2)		$	88,230	$	82,321

(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below. Nuclear generating facilities have been authorized by the CPUC to be fully depreciated by December 31, 2025.

(2) Includes $3.0 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.

106

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 in 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 3.61% in 2024, 3.56% in 2023, and 3.74% in 2022.  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.

Allowance for Funds Used During Construction

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 $111 million and $184 million during 2024, $82 million and $179 million during 2023, and $81 million and $184 million during 2022.

Asset Retirement Obligations

The following table summarizes the changes in ARO during 2024 and 2023, including nuclear decommissioning obligations:

(in millions)	2024		2023
ARO liability at beginning of year	$	5,512	$	5,912
Revision in estimated cash flows	(290)		(585)
Accretion	269		253
Liabilities settled	(47)		(68)
ARO liability at end of year	$	5,444	$	5,512

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 3 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 estimated decommissioning dates. 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 cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, 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 plant. 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 using a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

107

The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2024 and December 31, 2023 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2024, the Utility recorded a $222 million reduction to the nuclear decommissioning ARO to reflect the NRC’s decision to grant DCPP’s extended operations until 2030. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

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 DCPP and the Humboldt Bay independent spent fuel storage installation.  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.

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

The Utility participated in various government assistance programs during the years ended December 31, 2024, 2023, and 2022. 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, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, 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. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, 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 pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for DCPP Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of DCPP. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility received the final proceeds from the DWR loan agreement in 2024. For more information, see the DWR loan activity table below.

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The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:

(in millions)	2024		2023		2022
Long-term debt:
Beginning Balance - DWR loan outstanding	$	98	$	312	$	—
Proceeds received	980		—		350
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(117)		(124)		(38)
Operating and maintenance expense - Loan forgiveness and other adjustments	(75)		(90)		—
Long-term debt:
Ending Balance - DWR loan outstanding	$	886	$	98	$	312

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are 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 a number of factors, including actual costs incurred to extend the DCPP operations. 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 recognizes such funding as income and records a receivable related to government grants. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $265 million and $115 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $138 million and $76 million, as a deduction to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP.

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 on the Consolidated Balance Sheets.

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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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2024 and December 31, 2023, the SPV had net accounts receivable of $3.2 billion and $2.7 billion, respectively, and outstanding borrowings of zero and $1.5 billion respectively, under the Receivables Securitization Program. For more information, see Note 4 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 orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Recovery Funding LLC had outstanding borrowings of $3.2 billion and $1.8 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets.

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 first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.2 billion and $7.3 billion 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.

Non-Consolidated VIEs

Power Purchase Agreements

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, 2024, the Utility 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, 2024, it did not consolidate any of them.

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The Lakeside Building

BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building, which serves as the Utility’s principal administrative headquarters.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property, and the Utility does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to an issued letter of credit, base rent, and certain costs it pays according to the office lease agreement. As a result, the Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC. For more information, see “Oakland Headquarters Lease and Purchase” in Note 15 below.

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 ratably over the life of the fund based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. AB 1054 did not specify a period of coverage for the Wildfire Fund, and so this accounting treatment is subject to significant accounting judgments and estimates. 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 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 re-evaluate the estimated period of coverage annually and as required when additional information becomes available. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility initially estimated a period of coverage of 15 years. In the first quarter of 2024, the annual assessment resulted in the expected life of the Wildfire Fund increasing to 20 years after incorporating 2023 loss information into the dataset with no new events triggering a claim against the Wildfire Fund. PG&E Corporation and the Utility also assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that claims are made from the Wildfire Fund for catastrophic wildfires.

As of December 31, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $564 million in Other noncurrent liabilities, $301 million in Current assets - Wildfire Fund asset, and $4.1 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2024 and 2023, the Utility recorded amortization and accretion expense of $383 million and $567 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Consolidated Statements of Income.

For more information, see “Wildfire Fund under AB 1054” in Note 14 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 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, “Wildfire-Related Contingencies” in Note 14, and “Other Contingencies and Commitments” in Note 15 below.

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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, 2024 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
Beginning balance	$	(28)	$	18	$	2	$	(8)
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively)	—		—		1		1
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively)	(268)		29		—		(239)
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively)	260		(29)		—		231
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(2)		2		—		—
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively) (1)	1		(16)		—		(15)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)	2		14		—		16
Net current period other comprehensive income	(7)		—		1		(6)
Ending balance	$	(35)	$	18	$	3	$	(14)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2023 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		8		8
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively)	(196)		73		—		(123)
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively)	180		(73)		—		107
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(3)		2		—		(1)
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively)(1)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1)	2		12		—		14
Net current period other comprehensive income (loss)	(16)		—		8		(8)
Ending balance	$	(28)	$	18	$	2	$	(8)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

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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 it can ascertain an implicit discount rate from the leasing arrangement. 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 as paid in conformity with ratemaking.

Financing Leases

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024 and 2023, the Utility made total fixed cash payments of $315 million and $142 million, respectively, for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Financing leases were immaterial for the year ended December 31, 2022. 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 financing lease ROU assets and lease liabilities relate to the Oakland Headquarters lease discussed below.

Oakland Headquarters Lease and Purchase

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 also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2024, the Landlord has made available approximately 715,000 rentable square feet of the leased premises for the Utility’s use.

On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the legal parcel that contains the Lakeside Building (the “Property”), as modified. Pursuant to the Agreement of Purchase and Sale and Joint Escrow Instructions, the purchase price of the Property will be $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing on or before June 3, 2025. The Utility will also receive a credit of approximately $172 million towards the final payment, subject to adjustments, which represents the estimated outstanding principal balance of a loan carried by the Property that will be assigned to, and assumed by, the Utility at closing. The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing.

The execution of the Amendment to Office Lease Agreement on July 11, 2023 triggered a modification of the Lease, which resulted in the Lease being remeasured and reclassified from an operating lease to a financing lease during the year ended 2023.

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As of December 31, 2024, the Utility has recorded $807 million in Financing lease ROU assets, $282 million in accumulated amortization, $136 million in leasehold improvements, net of accumulated amortization, which includes $51 million that was provided to the Utility as lease incentives, and $575 million in current Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended. As of December 31, 2023, the Utility recorded $787 million in Financing lease ROU assets, $108 million in accumulated amortization, $218 million in leasehold improvements, net of accumulated amortization, which includes $134 million that was provided to the Utility as lease incentives, $259 million in current Financing lease liabilities, and $554 million in noncurrent Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended.

At December 31, 2024 and 2023, the Utility’s financing lease had a weighted average remaining lease term of 0.5 years and 1.6 years and a weighted average discount rate of 6.2% and 6.5%, respectively.

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

	Year Ended December 31,
(in millions)	2024		2023
Financing lease fixed cost:
Amortization of ROU assets	$	274	$	115
Interest on lease liabilities	42		27
Financing lease variable cost	9		3
Total financing lease costs	$	325	$	145

At December 31, 2024, the Utility expects to pay $591 million of lease payments in 2025.

Operating Leases

Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024, 2023, and 2022, the Utility made total cash payments, including fixed and variable, of $1.6 billion, $1.9 billion, and $2.3 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. 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 15 below.

At December 31, 2024 and 2023, the Utility’s operating leases had a weighted average remaining lease term of 7.5 years and 8.2 years and a weighted average discount rate of 6.5% and 6.4%, respectively.

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

	Year Ended December 31,
(in millions)	2024		2023		2022
Operating lease fixed cost	$	116	$	269	$	500
Operating lease variable cost	1,524		1,632		1,829
Total operating lease costs	$	1,640	$	1,901	$	2,329

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At December 31, 2024, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2024
2025	$	116
2026	112
2027	110
2028	97
2029	62
Thereafter	195
Total lease payments	692
Less imputed interest	(173)
Total	$	519

Recently Adopted Accounting Standards

Segment Reporting

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amended the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. PG&E Corporation and the Utility adopted this ASU in December 2024. See “Segment Reporting” above for additional disclosures as a result of adopting this ASU. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and income taxes paid disaggregated by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. PG&E Corporation and the Utility do not expect the guidance to have a significant impact on their Consolidated Financial Statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

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NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

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. The Utility does not earn a return on regulatory assets if the related costs do not accrue interest.

Noncurrent regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2024		2023
Pension benefits (1)	$	673	$	348	Indefinitely
Environmental compliance costs	1,172		1,218		32 years
Price risk management	167		160		up to 15.5 years
Catastrophic event memorandum account (2)	742		1,074		Various
Wildfire-related accounts (3)	1,697		2,915		1 - 3 years
Deferred income taxes (4)	4,771		3,543		Various
Financing costs (5)	216		196		Various
SB 901 securitization (6)	5,194		5,249		28 years
General rate case memorandum accounts (7)	95		1,291		Various
Other	834		1,195		Various
Total noncurrent regulatory assets	$	15,561	$	17,189

(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) 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, 2024 and 2023, $1 million and $43 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FHPMA, FRMMA, WMPMA, WMBA, VMBA and MGMA.

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

(5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings.

(6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds 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 5 below.

(7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 relates to revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2024 and 2023, the Utility had current regulatory liabilities of $1.2 billion. At December 31, 2024, current regulatory liabilities consisted primarily of billed revenues exceeding TO20 transmission revenue requirements. Current regulatory liabilities are included within Current liabilities-other in the Consolidated Balance Sheets.

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Noncurrent Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2024		2023
Cost of removal obligations (1)	$	8,943	$	8,191
Public purpose programs (2)	1,112		1,238
Employee benefit plans (3)	1,088		1,032
Transmission tower wireless licenses (4)	306		384
SFGO sale (5)	79		185
SB 901 securitization (6)	6,295		6,628
Wildfire self-insurance (7)	804		407
Other	790		1,379
Total noncurrent regulatory liabilities	$	19,417	$	19,444

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

(2) 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.

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

(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. Of the $306 million, $273 million will be refunded to FERC-jurisdictional customers, and $33 million will be refunded to CPUC-jurisdictional customers.

(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.

(6) 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. See Note 5 below.

(7) Represents amounts collected through rates designated for wildfire self-insurance. See Note 14 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 timing differences between when costs are incurred and customer revenues are collected.

Some regulatory balancing accounts receivable earn interest which is reflected in Interest income in the Consolidated Statements of Income. Some regulatory balancing accounts payable accrue interest which is reflected in Interest expense in the Consolidated Statements of Income. Interest income from balancing accounts receivable was $537 million, $547 million and $153 million for the years ended December 31, 2024, 2023, and 2022, respectively. Interest expense from balancing accounts payable was $323 million, $257 million and $81 million for the years ended December 31, 2024, 2023, and 2022, respectively.

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

	Receivable Balance at December 31,
(in millions)	2024		2023
Electric distribution (1)	$	1,591	$	1,092
Electric transmission (2)	117		99
Gas distribution and transmission (3)	387		144
Energy procurement (4)	1,066		1,002
Public purpose programs (5)	162		137
Wildfire-related accounts (6)	979		568
Insurance premium costs (7)	38		227
Residential uncollectibles balancing accounts (8)	260		507
Catastrophic event memorandum account (9)	500		413
General rate case memorandum accounts (10)	1,113		1,097
Other	1,014		374
Total regulatory balancing accounts receivable	$	7,227	$	5,660

	Payable Balance at December 31,
(in millions)	2024		2023
Electric transmission (2)	$	883	$	200
Gas distribution and transmission (3)	72		224
Energy procurement (4)	329		77
Public purpose programs (5)	882		299
SFGO sale	93		79
Wildfire-related accounts (6)	337		125
Nuclear decommissioning adjustment mechanism (11)	23		216
Other	550		449
Total regulatory balancing accounts payable	$	3,169	$	1,669

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

(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases.

(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(4) 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.

(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA.

(7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC.

(8) 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. The RUBA balance decreased from December 31, 2023 to December 31, 2024 mainly due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

(9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, and final decision on the 2023 WMCE interim rate relief.

(10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.

(11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision.

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NOTE 4: DEBT

Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2024:

(in millions)	Termination Date		Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2029	(1)	$	4,400	(2)	$	—	$	(633)	$	3,767
Utility Receivables Securitization Program (3)	June 2026		1,500		(4)	—		—		1,500		(4)
PG&E Corporation revolving credit facility	June 2027		500			—		—		500
Total credit facilities			$	6,400		$	—	$	(633)	$	5,767

(1) On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

(2) Includes a $2.0 billion letter of credit sublimit.

(3) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 April 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 26, 2024, the Utility amended its existing Receivables Securitization Program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

On June 28, 2024, the Utility amended its then-existing bridge term loan credit agreement to, among other things, (i) extend the maturity date from August 15, 2024 to December 16, 2024, and (ii) modify the mandatory prepayment provision to require the Utility to prepay term loans outstanding under such credit agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance of debt securities or incurrence of any debt under any bank credit facilities (excluding AB 1054 securitizations and the Utility’s revolving credit agreement). As of December 31, 2024, the bridge term loan was no longer outstanding.

On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

PG&E Corporation

On July 25, 2024, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date from June 22, 2026 to June 22, 2027 (subject to a one-year extension at the option of PG&E Corporation), and (ii) remove the cash coverage ratio covenant.

AB 1054 Securitization

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 16, 2024, CPUC issued a final decision approving a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the second quarter of 2024. In addition, the final decision authorized one or more series of recovery bonds and authorized the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.

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On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of senior secured recovery bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $300 million with an interest rate of 4.838% due June 1, 2035, (2) approximately $373 million with an interest rate of 5.231% due June 1, 2042, and (3) approximately $746 million with an interest rate of 5.529% due June 1, 2051. The payment dates for the senior secured recovery bonds are June 1 and December 1 of each year, commencing on June 1, 2025 and continuing until the final repayment date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the senior secured recovery bonds, including (1) the Recovery Property Servicing Agreement (“the Servicing Agreement”), (2) the Recovery Property Purchase and Sale Agreement (the “Sale Agreement”), and (3) the Administration Agreement (the “Administration Agreement”), each dated as of August 1, 2024.

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property created pursuant to the Wildfire Financing Law and the Financing Order (each as defined in the Sale Agreement) 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 Sale Agreement); 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 2 above.

Short-Term Borrowings

On September 5, 2024, the Utility completed the sale of $1.0 billion aggregate principal amount of Floating Rate First Mortgage Bonds due 2025. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

Long-Term Debt Issuances and Redemptions

Utility

On February 28, 2024, the Utility completed the sale of (i) $850 million aggregate principal amount of 5.550% First Mortgage Bonds due 2029, (ii) $1.1 billion aggregate principal amount of 5.800% First Mortgage Bonds due 2034 and (iii) $300 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The Utility used the net proceeds for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On September 5, 2024, the Utility completed the sale of $750 million aggregate principal amount of 5.900% First Mortgage Bonds due 2054. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

PG&E Corporation

On September 11, 2024, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes, including to fully prepay all loans outstanding under its existing term loan agreement in an aggregate principal amount equal to $500 million. During the year ended December 31, 2024, PG&E Corporation recognized a $9 million loss within Interest expense on the Consolidated Statements of Income related to the early extinguishment and associated write-off of deferred debt issuance costs of the term loan agreement.

On November 15, 2024, PG&E Corporation completed the sale of an additional $500 million aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes.

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Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% convertible senior secured notes due December 1, 2027 (the “Convertible Notes”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

•during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or

•upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.

On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2024, none of the conditions allowing holders of the Convertible Notes to convert had been met.

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The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2024 and 2023, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.13 billion and $2.12 billion, with unamortized debt issuance costs of $20 million and $27 million, respectively, in Long-term debt. For the year ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $98 million and $7 million, respectively.

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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, 2024		December 31, 2023
PG&E Corporation
Term Loan	7.85%	$	—	$	500
Convertible Notes due 2027	4.25%	2,150		2,150
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Junior Subordinated Notes due 2055	7.38%	1,500		—
Unamortized discount, premium and debt issuance costs, net		(39)		(51)
Total PG&E Corporation Long-Term Debt		5,611		4,599
Utility
First Mortgage Bonds - Stated Maturity:
2024	3.40% - 3.75%	—		800
2025	3.45% - 4.95%	1,925		1,925
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 4.65%	1,975		1,975
2029	4.20% - 6.10%	2,100		1,250
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		1,050
2033	6.15% - 6.40%	1,900		1,900
2034	5.80% - 6.95%	1,900		800
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		550
2053	6.70% - 6.75%	2,300		2,000
2054	5.90%	750		—
Less: current portion, net of unamortized discount and debt issuance costs		(1,924)		(800)
Unamortized discount, premium and debt issuance costs, net		(226)		(246)
Total Utility First Mortgage Bonds		36,927		35,831
Recovery Bonds (1)		10,367		9,124
Less: current portion		(222)		(176)
DWR Loan (2)		886		98
Credit Facilities
Receivables Securitization Program	6.75%	—		1,499
2-Year Term Loan	6.60%	—		400
Less: current portion		—		(400)
Total Utility Long-Term Debt		47,958		46,376
Total PG&E Corporation Consolidated Long-Term Debt		$	53,569	$	50,975

(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.

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Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2024 are reflected in the table below:

(in millions, except interest rates)	2025			2026			2027			2028			2029			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	4.25		%	5.00		%	—		%	6.53		%	5.39		%
Fixed rate obligations	$	—		$	—		$	2,150		$	1,000		$	—		$	2,500		$	5,650
Utility (1)
Average fixed interest rate	3.82		%	3.10		%	3.22		%	3.58		%	5.52		%	4.72		%	4.44		%
Fixed rate obligations	$	1,925		$	2,551		$	3,000		$	1,975		$	2,100		$	27,526		$	39,077
Recovery Bonds (2)
AB 1054 obligations	$	88		$	81		$	84		$	88		$	91		$	2,728		$	3,160
SB 901 obligations	135			140			146			152			159			6,475			7,207
Total consolidated debt	$	2,148		$	2,772		$	5,380		$	3,215		$	2,350		$	39,229		$	55,094

(1) The balance excludes DWR loan, see Note 2 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 11 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. 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, 2024.

Upon issuance of senior secured 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, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $650 million is required to be contributed no later than March 31, 2025 unless certain conditions are met requiring an earlier contribution or unless otherwise ordered by the CPUC. 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 sold PG&E Corporation common stock shares it held, the SB 901 securitization regulatory liability increased accordingly. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. 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, 2024, the Utility recorded $328 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income. During the year ended December 31, 2023, the Utility recorded SB 901 securitization charges, net, of $1.3 billion for tax benefits realized within Income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and $322 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income.

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The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:

	SB 901 securitization regulatory asset
(in millions)	2024		2023
Balance at January 1	$	5,249	$	5,378
Amortization	(55)		(129)
Balance at December 31	$	5,194	$	5,249

	SB 901 securitization regulatory liability
(in millions)	2024		2023
Balance at January 1	$	(6,628)	$	(5,800)
Amortization	383		451
Additions(1)	(50)		(1,279)
Balance at December 31	$	(6,295)	$	(6,628)

(1) Includes $16 million and $12 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2024 and 2023, respectively.

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 2,193,573,536 shares of common stock outstanding at December 31, 2024. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2024.

On December 4, 2024, PG&E Corporation issued 55,961,070 shares of common stock, no par value, for cash proceeds of approximately $1.13 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.

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 deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate value of the 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.

Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore 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. Accordingly, although PG&E Corporation had 2,671,320,389 common shares outstanding as of February 5, 2025, only 2,193,576,799 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date.

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

CPUC holding company rules require that the Utility’s dividend policy be established by the Utility’s Board of Directors on the same basis as if the Utility were a stand-alone utility company, and that the capital requirements of Utility, as deemed to be necessary to meet the Utility’s electricity service obligations, shall receive first priority from the Boards of Directors of both PG&E Corporation and the Utility. The CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. The CPUC has granted the Utility a temporary waiver from compliance with its authorized capital structure until 2025 for the financing in place upon the Utility’s emergence from Chapter 11.

California law also requires that for a dividend to be declared: (a) retained earnings must equal to or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation’s assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. A California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature.

Additionally, neither PG&E Corporation nor the Utility may pay common stock dividends unless all cumulative preferred dividends on PG&E Corporation’s Mandatory Convertible Preferred Stock and the Utility’s preferred stock, respectively, have been paid.

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 and the Utility’s 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.

Utility

On each of February 13, May 16, and September 19, and November 29, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million, $500 million, $500 million, and $575 million, which were paid to PG&E Corporation on March 25, June 3, September 20, and December 24, 2024, respectively.

PG&E Corporation

On each of February 13, May 16, and September 19, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, each declaration totaling $21 million, which were paid on April 15, July 15, and October 15, 2024, to holders of record as of March 28, June 28 and September 30, 2024, respectively. On November 29, 2024, the Board of Directors of PG&E Corporation declared a new quarterly common stock dividend of $0.025 per share, totaling $55 million, which was paid on January 15, 2025, to holders of record as of December 31, 2024.

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 55,900,800 shares were available for future awards at December 31, 2024.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2024:

(in millions)	2024		2023		2022
Restricted stock units	67		64		60
Performance shares	31		27		55
Total compensation expense (pre-tax)	$	98	$	91	$	115
Total compensation expense (after-tax)	$	71	$	65	$	83

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, 2024, 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 2024 or 2023.

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, 2024.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2024:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1	1,396,261	$	8.2
Granted (1)	—	—
Exercised	—	—
Forfeited or expired	(652,298)	6.89
Outstanding at December 31	743,963	10.23		2.58
Vested or expected to vest at December 31	743,963	10.23		2.58
Exercisable at December 31	743,963	$	10.23	2.58

(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 2024, 2023, and 2022 was $16.74, $15.70, and $11.40, respectively.  The total fair value of restricted stock units that vested during 2024, 2023, and 2022 was $62 million, $64 million, and $46 million, respectively.  The tax benefit from restricted stock units that vested in 2024 was $21 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, 2024, $90 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.52 years.

The following table summarizes restricted stock unit activity for 2024:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	9,268,425	$	13.29
Granted	5,273,850	16.74
Vested	(4,922,000)	12.62
Forfeited	(196,693)	15.27
Nonvested at December 31	9,423,582	$	15.52

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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 awards based on internal metrics.  The weighted average grant-date fair value for performance shares granted during 2024, 2023, and 2022 was $16.94, $13.39, and $13.44 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, 2024, $48 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.17 years.

The following table summarizes activity for performance shares in 2024:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	6,602,292	$	14.06
Granted	2,714,196	16.94
Vested	(1,779,695)	10.70
Forfeited	(356,587)	13.07
Nonvested at December 31	7,180,206	$	15.52

NOTE 7: PREFERRED STOCK

PG&E Corporation

PG&E Corporation has authorized 400 million shares of preferred stock.

On December 5, 2024, PG&E Corporation issued 32,200,000 shares of 6.000% Series A Mandatory Convertible Preferred Stock, at $50.00 per share, for cash proceeds of approximately $1.6 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.

Each share of the Mandatory Convertible Preferred Stock will automatically convert on December 1, 2027. The number of shares of common stock issuable on conversion of Mandatory Convertible Preferred Stock will not be more than 2.4331 shares of common stock and not less than 1.9465 shares of common stock.

Other than during a Fundamental Change Conversion Period (as defined in the PG&E Corporation Preferred Stock Certificate of Designation), at any time prior to December 1, 2027, holders of Mandatory Convertible Preferred Stock have the option to elect to convert their shares of the Mandatory Convertible Preferred Stock, in whole or in part (but in no event in increments of less than one share of the Mandatory Convertible Preferred Stock), into shares of common stock at the Minimum Conversion Rate of 1.9465 shares of common stock per share of Mandatory Convertible Preferred Stock, subject to adjustment as described in the Preferred Stock Preliminary Prospectus Supplement.

Dividends on the Mandatory Convertible Preferred Stock are cumulative. All shares of the Mandatory Convertible Preferred Stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of the Mandatory Convertible Preferred Stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The expected dividend payable on the first dividend payment date is approximately $0.7167 per share of the Mandatory Convertible Preferred Stock. Each subsequent dividend is expected to be $0.75 per share of the Mandatory Convertible Preferred Stock. The dividends will be declared on the February 15, May 15, August 15 and November 15 immediately preceding the relevant dividend payment date.

The Mandatory Convertible Preferred Stock ranks senior to PG&E Corporation’s common stock with respect to the payment of dividends. Accordingly, unless accumulated dividends have been paid on all of the Mandatory Convertible Preferred Stock through the most recently completed dividend period, no dividends may be declared or paid on PG&E Corporation’s common stock and PG&E Corporation will not be permitted to repurchase any of its common stock, subject to limited exceptions.

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On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share for the period from and including December 5, 2024 to and excluding March 1, 2025, to be payable on March 1, 2025, to holders of record as of February 14, 2025.

Utility

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, 2024 and 2023, 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.

At December 31, 2024, 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, 2024, annual dividends on the Utility’s redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  The Utility paid $14 million of dividends on preferred stock in 2024. The Utility paid approximately $70 million of dividends on preferred stock in 2022, of which approximately $59 million was paid in arrears. On each of February 13, May 16, and September 19, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on May 15, August 15, and November 15, 2024, respectively, to holders of record as of April 30, July 31, and October 31, 2024. On November 29, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on February 15, 2025, to holders of record as of January 31, 2025.

NOTE 8: 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 2024, 2023, and 2022.

	Year Ended December 31,
(in millions, except per share amounts)	2024		2023		2022
Income (loss) available for common shareholders	$	2,475	$	2,242	$	1,800
Weighted average common shares outstanding, basic (1)	2,141		2,064		1,987
Add incremental shares from assumed conversions:
Employee share-based compensation	6		6		8
Equity Units	—		68		137
Weighted average common shares outstanding, diluted	2,147		2,138		2,132
Total earnings (loss) per common share, diluted	$	1.15	$	1.05	$	0.84

(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant number of options and securities that were antidilutive. For the year ended December 31, 2024, the calculation of outstanding common shares on a diluted basis excluded the impacts of the Mandatory Convertible Preferred Stock (see Note 7 above), which were antidilutive. In addition, as a result of an irrevocable election made on December 8, 2023 to fix the settlement method to combination settlement, the Convertible Notes (as defined in Note 4) did not have a material impact on the calculation of diluted EPS.

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NOTE 9: INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the 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 benefit by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2024		2023		2022		2024		2023		2022
Current:
Federal	$	2	$	(1)	$	(1)	$	2	$	(1)	$	(1)
State	(78)		—		—		(78)		—		—
Deferred:
Federal	(137)		(1,047)		(943)		(72)		(981)		(852)
State	15		(507)		(389)		45		(477)		(348)
Tax credits	(2)		(2)		(5)		(2)		(2)		(5)
Income tax benefit	$	(200)	$	(1,557)	$	(1,338)	$	(105)	$	(1,461)	$	(1,206)

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The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2024		2023		2024		2023
Deferred income tax assets:
Tax carryforwards	$	9,429	$	9,132	$	8,955	$	8,740
Compensation	171		145		86		82
GHG allowance	471		361		471		361
Wildfire-related claims (1)	295		1,069		295		1,069
Operating lease liability	78		142		78		142
Transmission tower wireless licenses	251		250		251		250
Bad debt	127		134		127		134
Other (2)	140		130		137		109
Total deferred income tax assets	$	10,962	$	11,363	$	10,400	$	10,887
Deferred income tax liabilities:
Property-related basis differences	11,021		10,058		11,009		10,047
Regulatory balancing accounts	878		1,433		878		1,433
Debt financing costs	390		428		390		428
Operating lease ROU asset	78		142		78		142
Income tax regulatory asset (3)	1,335		991		1,335		991
Environmental reserve	248		200		248		200
Other (4)	94		91		94		82
Total deferred income tax liabilities	$	14,044	$	13,343	$	14,032	$	13,323
Total net deferred income tax liabilities	$	3,082	$	1,980	$	3,632	$	2,436

(1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in 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 TCJA.

(4) Amounts primarily include property taxes and prepaid expense.

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,
	2024		2023		2022		2024		2023		2022
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)	(2.0)		(57.9)		(75.8)		(0.8)		(34.4)		(26.9)
Effect of regulatory treatment of fixed asset differences (2)	(28.3)		(63.4)		(123.8)		(24.7)		(40.1)		(49.2)
Tax credits	(0.7)		(2.2)		(3.2)		(0.7)		(2.2)		(1.3)
Fire Victim Trust (3)	—		(126.9)		(160.9)		—		(80.2)		(64.0)
Other, net (4)	1.2		2.2		12.9		1.2		1.1		2.2
Effective tax rate	(8.8)	%	(227.2)	%	(329.8)	%	(4.0)	%	(134.8)	%	(118.2)	%

(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 2024, 2023, and 2022, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA passed in December 2017. In addition, for the 2024 tax year, PG&E Corporation and the Utility will implement the accounting method change related to gas repairs in accordance with Revenue Procedure 2013-15.

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(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023 and 2022 and a deferred tax asset write-off associated with the grantor trust election for the Fire Victim Trust in 2021.

(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)	2024		2023		2022		2024		2023		2022
Balance at beginning of year	$	616	$	570	$	498	$	616	$	570	$	498
Additions for tax position taken during a prior year	—		1		—		—		1		—
Reductions for tax position taken during a prior year	(257)		—		(1)		(257)		—		(1)
Additions for tax position taken during the current year	95		45		73		95		45		73
Settlements	—		—		—		—		—		—
Balance at end of year	$	454	$	616	$	570	$	454	$	616	$	570

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2024 for PG&E Corporation and the Utility was $106 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, 2024, 2023, and 2022, these amounts were immaterial.

Tax Audits

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The IRS is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. On June 4, 2024, the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. As a result, in the year ended December 31, 2024, PG&E Corporation determined that it is no longer more likely than not that its deduction related to a portion of the customer bill credits would ultimately be sustained. Accordingly, PG&E Corporation has decreased its Income tax benefit by $70 million in the year ended December 31, 2024 related to state and federal income taxes. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Carryforwards

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

(in millions)	December 31, 2024		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,369	2031 - 2036
Net operating loss carryforward - Post-2017	30,288		N/A
Tax credit carryforward	125		2029 - 2041
State:
Net operating loss carryforward	$	34,901	2039 - 2041
Tax credit carryforward	146		Various

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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.

NOTE 10: 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, 2024	December 31, 2023
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	179,257,247	196,063,296
	Options	37,717,500	30,695,000
Electricity (MWh)	Forwards, futures, and swaps	8,576,078	9,169,967
	Options	1,663,200	92,400
	Congestion Revenue Rights (3)	123,040,895	170,465,674

(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, 2024, 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	$	186	$	(16)	$	—	$	170
Noncurrent assets – other	233		—		—		233
Current liabilities – other	(152)		16		—		(136)
Noncurrent liabilities – other	(167)		—		—		(167)
Total commodity risk	$	100	$	—	$	—	$	100

As of December 31, 2023, 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	$	134	$	(8)	$	50	$	176
Other noncurrent assets – other	280		—		—		280
Current liabilities – other	(172)		8		46		(118)
Noncurrent liabilities – other	(160)		—		—		(160)
Total commodity risk	$	82	$	—	$	96	$	178

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 derivative 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, 2024, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 11: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value.  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, 2024
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	826	$	—	$	—	$	—	$	826
Pacific Energy Risk Solutions, LLC
Short-term investments	905		—		—		—		905
Total Pacific Energy Risk Solutions, LLC	905		—		—		—		905
Nuclear decommissioning trusts
Short-term investments	53		—		—		—		53
Global equity securities	2,228		—		—		—		2,228
Fixed-income securities	1,250		1,027		—		—		2,277
Assets measured at NAV	—		—		—		—		22
Total nuclear decommissioning trusts (2)	3,531		1,027		—		—		4,580
Customer credit trust
Short-term investments	1		—		—		—		1
Global equity securities	186		—		—		—		186
Fixed-income securities	46		144		—		—		190
Total customer credit trust	233		144		—		—		377
Price risk management instruments (Note 10)
Electricity	—		26		383		(6)		403
Gas	—		10		—		(10)		—
Total price risk management instruments	—		36		383		(16)		403
Rabbi trusts
Short-term investments	107		—		—		—		107
Global equity securities	6		—		—		—		6
Life insurance contracts	—		66		—		—		66
Total rabbi trusts	113		66		—		—		179
Long-term disability trust
Short-term investments	4		—		—		—		4
Assets measured at NAV	—		—		—		—		130
Total long-term disability trust	4		—		—		—		134
TOTAL ASSETS	$	5,612	$	1,273	$	383	$	(16)	$	7,404
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	37	$	248	$	(6)	$	279
Gas	—		34		—		(10)		24
TOTAL LIABILITIES	$	—	$	71	$	248	$	(16)	$	303

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

(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.

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	Fair Value Measurements
	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	203	$	—	$	—	$	—	$	203
Nuclear decommissioning trusts
Short-term investments	52		—		—		—		52
Global equity securities	2,144		—		—		—		2,144
Fixed-income securities	1,168		909		—		—		2,077
Assets measured at NAV	—		—		—		—		18
Total nuclear decommissioning trusts (2)	3,364		909		—		—		4,291
Customer credit trust
Short-term investments	49		—		—		—		49
Global equity securities	71		—		—		—		71
Fixed-income securities	29		84		—		—		113
Total customer credit trust	149		84		—		—		233
Price risk management instruments (Note 10)
Electricity	—		7		404		(1)		410
Gas	—		3		—		43		46
Total price risk management instruments	—		10		404		42		456
Rabbi trusts
Short-term investments	102		—		—		—		102
Global equity securities	5		—		—		—		5
Life insurance contracts	—		65		—		—		65
Total rabbi trusts	107		65		—		—		172
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		139
Total long-term disability trust	7		—		—		—		146
TOTAL ASSETS	$	3,830	$	1,068	$	404	$	42	$	5,501
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	43	$	213	$	(6)	$	250
Gas	—		76		—		(48)		28
TOTAL LIABILITIES	$	—	$	119	$	213	$	(54)	$	278

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

(2) Represents amount before deducting $717 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, 2024 or 2023.

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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.

Pacific Energy Risk Solutions, LLC

Investments held in Pacific Energy Risk Solutions, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.

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.

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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 10 above.

	Fair Value
(in millions)	At December 31, 2024				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	366	$	121	Market approach	CRR auction prices	$ (951) - 50,044 / 2
Power purchase agreements	$	17	$	127	Discounted cash flow	Forward prices	$ 0 - 126 / 47

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

	Fair Value
(in millions)	At December 31, 2023				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	357	$	134	Market approach	CRR auction prices	$ (924) - 16,697 / 1
Power purchase agreements	$	47	$	79	Discounted cash flow	Forward prices	$ 1 - 190 / 60

(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, 2024 and 2023, respectively:

	Price Risk Management Instruments
(in millions)	2024		2023
Asset balance as of January 1	$	191	$	199
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(64)		(8)
Asset balance as of December 31	$	127	$	191

(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, 2024 and December 31, 2023, 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, 2024				At December 31, 2023
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	5,358	$	5,829	$	4,548	$	4,695
Utility	37,812		34,532		35,909		32,866

(1) As of December 31, 2024, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.

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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, 2024
Nuclear decommissioning trusts
Short-term investments	$	54	$	—	$	(1)	$	53
Global equity securities	353		1,907		(10)		2,250
Fixed-income securities	2,341		20		(84)		2,277
Total (1)	$	2,748	$	1,927	$	(95)	$	4,580
As of December 31, 2023
Nuclear decommissioning trusts
Short-term investments	$	52	$	—	$	—	$	52
Global equity securities	381		1,792		(11)		2,162
Fixed-income securities	2,103		60		(86)		2,077
Total (1)	$	2,536	$	1,852	$	(97)	$	4,291

(1) Represents amounts before deducting $747 million and $717 million as of December 31, 2024 and December 31, 2023, 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, 2024
Less than 1 year	$	35
1–5 years	742
5–10 years	517
More than 10 years	983
Total maturities of fixed-income securities	$	2,277

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

(in millions)	2024		2023		2022
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	1,980	$	2,235	$	3,316
Gross realized gains on securities	255		80		2
Gross realized losses on securities	(63)		(74)		(3)

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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, 2024
Customer credit trust
Short-term investments	$	1	$	—	$	—	$	1
Global equity securities	161		28		(3)		186
Fixed-income securities	193		1		(4)		190
Total	$	355	$	29	$	(7)	$	377
As of December 31, 2023
Customer credit trust
Short-term investments	$	49	$	—	$	—	$	49
Global equity securities	56		16		(1)		71
Fixed-income securities	111		2		—		113
Total	$	216	$	18	$	(1)	$	233

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

	As of
(in millions)	December 31, 2024
Less than 1 year	$	—
1–5 years	44
5–10 years	36
More than 10 years	110
Total maturities of fixed-income securities	$	190

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

(in millions)	2024		2023		2022
Proceeds from sales and maturities of customer credit trust investments	$	398	$	556	$	250
Gross realized gains on securities	10		23		10
Gross realized losses on securities (1)	(8)		(19)		(41)

(1) Includes $0 million and $4 million of impaired debt securities which were written down to their respective fair values during the years ended December 31, 2024 and 2023, respectively.

NOTE 12: 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.

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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 2024 and 2023:

Pension Plan

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	17,211	$	16,369
Actual return on plan assets	218		1,518
Company contributions	337		336
Benefits and expenses paid	(999)		(1,012)
Fair value of plan assets at end of year	$	16,767	$	17,211
Change in benefit obligation:
Benefit obligation at beginning of year	$	17,697	$	16,608
Service cost for benefits earned	396		379
Interest cost	916		913
Actuarial loss (gain) (1)	(424)		809
Benefits and expenses paid	(1,000)		(1,012)
Benefit obligation at end of year (2)	$	17,585	$	17,697
Funded Status:
Current liability	$	(10)	$	(9)
Noncurrent liability	(808)		(477)
Net liability at end of year	$	(818)	$	(486)

(1) The actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions; the actuarial loss for the year ended December 31, 2023 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.3 billion at December 31, 2024 and 2023, respectively.

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Postretirement Benefits Other than Pensions

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,499	$	2,336
Actual return on plan assets	74		260
Company contributions	5		5
Plan participant contribution	84		81
Benefits and expenses paid	(191)		(183)
Fair value of plan assets at end of year	$	2,471	$	2,499
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,377	$	1,339
Service cost for benefits earned	41		38
Interest cost	71		73
Actuarial loss (gain) (1)	(123)		8
Benefits and expenses paid	(174)		(165)
Federal subsidy on benefits paid	3		3
Plan participant contributions	84		81
Benefit obligation at end of year	$	1,279	$	1,377
Funded Status: (2)
Noncurrent asset	$	1,192	$	1,122
Noncurrent liability	—		—
Net asset at end of year	$	1,192	$	1,122

(1) The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets. The actuarial loss for the year ended December 31, 2023 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations, offset by favorable changes in claims cost and demographic assumptions.

(2) At December 31, 2024 and 2023, 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 $261 million and $296 million as of December 31, 2024, and $275 million and $292 million as of December 31, 2023, respectively.

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 Plan” below.  Post-retirement medical and life insurance plans are included in “Postretirement Benefits Other than Pensions” 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)	2024		2023		2022
Service cost for benefits earned (1)	$	396	$	379	$	575
Interest cost	916		913		692
Expected return on plan assets	(1,014)		(981)		(1,189)
Amortization of prior service cost	(3)		(4)		(4)
Amortization of net actuarial loss	1		1		2
Net periodic benefit cost	296		308		76
Less: transfer to regulatory account (2)	39		25		254
Total expense recognized	$	335	$	333	$	330

(1) A portion of service costs are capitalized pursuant to ASC 715.

(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)	2024		2023		2022
Service cost for benefits earned (1)	$	41	$	38	$	62
Interest cost	71		73		53
Expected return on plan assets	(139)		(132)		(130)
Amortization of prior service cost	3		3		7
Amortization of net actuarial gain	(23)		(19)		(40)
Special termination benefits	—		—		22
Net periodic benefit cost	$	(47)	$	(37)	$	(26)

(1) A portion of service costs are capitalized pursuant to ASC 715.

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,
	2024		2023		2022		2024	2023	2022
Discount rate	5.76	%	5.21	%	5.54	%	5.71 - 5.76%	5.18 - 5.22%	5.50 - 5.54%
Rate of future compensation increases	4.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.40	%	6.00	%	6.10	%	3.90 - 7.20%	3.70 - 7.00%	3.70 - 7.30%
Interest crediting rate for cash balance plan	4.41	%	3.86	%	4.19	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2024 was 7.50%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2033 and beyond.

Expected rates of return on plan assets were developed by estimating future asset class 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 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 6.4% compares to a ten-year actual return of 5.1%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 858 Aa-grade non-callable bonds at December 31, 2024.  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
	2025		2024		2023		2025		2024		2023
Global equity securities	26	%	26	%	26	%	30	%	29	%	28	%
Absolute return	1	%	1	%	1	%	—	%	—	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	3	%
Fixed-income securities	65	%	65	%	65	%	67	%	68	%	68	%
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, 2024 and 2023.

	Fair Value Measurements
	At December 31,
	2024								2023
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	126	$	47	$	—	$	173	$	565	$	86	$	—	$	651
Global equity securities	1,310		—		—		1,310		1,270		—		—		1,270
Real assets	437		—		—		437		472		—		—		472
Fixed-income securities	2,180		6,367		16		8,563		1,926		6,802		13		8,741
Assets measured at NAV	—		—		—		6,284		—		—		—		6,080
Total	$	4,053	$	6,414	$	16	$	16,767	$	4,233	$	6,888	$	13	$	17,214
PBOP Plans:
Short-term investments	$	27	$	—	$	—	$	27	$	30	$	—	$	—	$	30
Global equity securities	60		—		—		60		66		—		—		66
Real assets	20		—		—		20		32		—		—		32
Fixed-income securities	431		751		1		1,183		422		795		1		1,218
Assets measured at NAV	—		—		—		1,181		—		—		—		1,160
Total	$	538	$	751	$	1	$	2,471	$	550	$	795	$	1	$	2,506
Total plan assets at fair value							$	19,238							$	19,720

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of zero and $10 million at December 31, 2024 and 2023, 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.

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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, 2024 or 2023.

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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, 2024 and 2023:

(in millions)
For the year ended December 31, 2024	Fixed-Income
Balance at beginning of year	$	13
Actual return on plan assets:
Relating to assets still held at the reporting date	9
Relating to assets sold during the period	(9)
Purchases, issuances, sales, and settlements:
Purchases	14
Settlements	(11)
Balance at end of year	$	16
(in millions)
For the year ended December 31, 2023	Fixed-Income
Balance at beginning of year	$	8
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(1)
Purchases, issuances, sales, and settlements:
Purchases	10
Settlements	(6)
Balance at end of year	$	13

There were no material transfers out of Level 3 in 2024 or 2023.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $337 million to the pension benefit plans, $31 million to the long-term disability trusts, and $5 million to the other postretirement benefit plans in 2024.  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. The Utility’s pension benefits met all funding requirements under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2025. PG&E Corporation and the Utility plan to contribute $31 million to the long-term disability trusts in 2025, as authorized in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2024, 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
2025	969	81	(1)
2026	1,055	84	(1)
2027	1,083	87	(2)
2028	1,109	89	(2)
2029	1,133	91	(2)
2030-2034	5,997	473	(11)

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There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and 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 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 $175 million, $158 million, and $144 million in 2024, 2023, and 2022, respectively. PG&E Corporation’s default matching contributions under its 401(k) plan are in cash.

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

NOTE 13: 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)	2024		2023		2022
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	66	$	80	$	104
Utility employee benefit due to PG&E Corporation	81		74		85

At December 31, 2024 and 2023, the Utility had receivables of $25 million and $26 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 $11 million and $24 million, respectively, to PG&E Corporation included in Accounts payable – other on the Utility’s Consolidated Balance Sheets.

NOTE 14: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that 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.

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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. 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 or the upper end of the range because, as described below, 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.

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. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel 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 complaints, except that the applicable statutes of limitations have run for the 2019 Kincade and 2021 Dixie fires. 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 power 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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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.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through December 31, 2024.

Payments (in millions)
2019 Kincade Fire	$	958
2021 Dixie Fire	1,359
2022 Mosquito Fire	18
Total at December 31, 2024	$	2,335

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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 133 complaints on behalf of at least 2,960 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. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024 the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation. The court scheduled a trial on their claims for August 4, 2025. The parties have reached settlements in principle for these claims and expect that the trial date will be vacated.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), extending their time to file a complaint.

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 $1.125 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $100 million, of which $75 million was recorded in the third quarter and $25 million was recorded in the fourth quarter, for an aggregate liability of $1.225 billion (before available insurance).

150

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.225 billion do not include, among other things: (i) any punitive damages, (ii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, or (iii) 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 losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	458
Accrued Losses	100
Payments	(291)
Balance at December 31, 2024	$	267

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million, which was fully collected as of December 31, 2023.

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, through its ongoing investigation, 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” below.) 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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 182 complaints on behalf of at least 8,681 individual plaintiffs related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. The court had previously scheduled two trial dates for October 14, 2024 and February 24, 2025. The court has vacated both of those dates and set a new bellwether trial date for June 23, 2025.

The Collins Pine Company and a group of timber companies filed a complaint against PG&E Corporation and the Utility on April 10, 2024. PG&E Corporation and the Utility answered this complaint on May 28, 2024.

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Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer to portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer.

On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

PG&E Corporation and the Utility are aware of a separate putative class complaint. On August 23, 2024, PG&E Corporation and the Utility demurred to the putative class complaint. On January 13, 2025, the court issued an order pursuant to which plaintiff has 30 days to amend the complaint or the case will be abated.

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 $1.6 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $325 million, of which $275 million was recorded in the third quarter and $50 million was recorded in the fourth quarter, for an aggregate liability of $1.925 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.925 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 Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring 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 other than Cal Fire 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 parks 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 losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	870
Accrued Losses	325
Payments	(628)
Balance at December 31, 2024	$	567

As of December 31, 2024, the Utility recorded an insurance receivable of $527 million for probable insurance recoveries in connection with the 2021 Dixie fire.

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The Utility recorded an aggregate Wildfire Fund receivable of $925 million for probable recoveries in connection with the 2021 Dixie fire, of which it had received $169 million as of December 31, 2024. 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. As of December 31, 2024, the Utility also recorded a $94 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 $508 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.

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, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) 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, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. 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 ongoing.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 25 complaints on behalf of at least 2,738 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency (“PCWA”), a complaint on behalf of the Middle Fork Project Finance Authority, and complaints on behalf of six public entities. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. On April 24, 2024, PG&E Corporation and the Utility filed cross-complaints against PCWA, alleging that conduct by PCWA was a substantial cause of the 2022 Mosquito fire. The cross-complaints seek property damages, indemnification, attorneys’ fees, and other damages. On January 28, 2025, the court entered an order setting the first individual claimant bellwether trial for November 7, 2025.

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. 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 a liability in the aggregate amount of $100 million as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of December 31, 2024.

PG&E Corporation’s and the Utility’s accrued estimated losses 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, or (iv) any other amounts that are not reasonably estimable.

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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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	85
Accrued Losses	—
Payments	(3)
Balance at December 31, 2024	$	82

As of December 31, 2024, the Utility recorded an insurance receivable of $90 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of December 31, 2024, the Utility also recorded a $7 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 $53 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, through rates, and from 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,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2024 are:

Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	527	$	90
FERC TO rates	94		7
WEMA	508		53
Wildfire Fund	925		—
Probable recoveries at December 31, 2024 (1)	$	2,054	$	150

(1) Includes legal costs of $123 million and $50 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2024.

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

Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.

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Insurance Receivable

As of December 31, 2024, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $527 million and $90 million in connection with 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. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2023:

Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2023	$	326	$	63	$	389
Accrued insurance recoveries	1		27		28
Reimbursements	(300)		—		(300)
Balance at December 31, 2024	$	27	$	90	$	117

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 reasonableness 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, 2024, the Utility recorded reductions of $94 million and $7 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, 2024, 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 $508 million and $53 million, respectively, as regulatory assets in the WEMA.

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Wildfire Fund under AB 1054

On July 12, 2019, AB 1054 became law. The law 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 arising from wildfires 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, 2024 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. This reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the IOU’s electric transmission and distribution rate base in the year of the prudency determination. A utility would not be required to reimburse the Wildfire Fund for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Utility, the disallowance cap would be approximately $4.1 billion for 2024. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2024 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. 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 11, 2024, the OEIS approved the Utility’s 2024 application and issued the Utility’s 2024 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts in the fund are exhausted. The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable 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 the participating 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 PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, 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. AB 1054 authorizes the reimbursement of funds where a participating utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

As of December 31, 2024, PG&E Corporation and the Utility recorded $600 million and $156 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2023:

Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2023	$	600
Accrued Wildfire Fund recoveries	325
Claims paid by Wildfire Fund	(169)
Balance at December 31, 2024	$	756

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For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” 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, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, 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 due to the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, 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 settlement.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its 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.

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 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 of 1933, as amended, 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 former officers and directors, and the underwriters. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation.

On August 21, 2024, the District Court entered an order setting a briefing schedule for renewed motions to dismiss the third amended complaint. Opening briefs were filed on October 24, 2024, opposition briefs were filed December 20, 2024, and reply briefs were filed January 31, 2025.

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Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and proceeds from any insurance 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. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities 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. Such claims could 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 January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing 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.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with 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 continue to prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

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Indemnification Obligations

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.

PG&E Corporation and the Utility additionally may have 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 March 28, 2025.

NOTE 15: 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 assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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

Rates under the TO rate case for 2017 (“TO18”) were in effect from March 1, 2017 through February 28, 2018. Rates under the TO rate case for 2018 (“TO19”) were in effect from March 1, 2018 through April 30, 2019. Rates under the TO rate case for 2019 (“TO20”) were in effect from May 1, 2019 through December 31, 2023. The FERC previously approved settlement agreements for TO19 and TO20 resolving most issues.

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On May 31, 2024, the Utility submitted a settlement to the FERC resolving all outstanding issues in the TO18, TO19, and TO20 rate cases. On August 22, 2024, the FERC approved the settlement. As a result, the Utility will refund $236 million, $358 million, and $405 million (plus applicable interest) to retail customers for TO18, TO19, and TO20, respectively. Approval of the settlement did not have a material impact on the Utility’s financial statements in the year ended December 31, 2024. The refunds will occur over 12 months, effective January 1, 2025. The settlement provided that the Utility may seek authorization from the CPUC through a memorandum account to recover up to $473 million through CPUC jurisdictional rates of the general, common and intangible plant cost that had been allocated to FERC-jurisdictional rates in TO18, TO19, and TO20.

2022 WMCE Interim Rate Relief Subject to Refund

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 the implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

2023 WMCE Interim Rate Relief Subject to Refund

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 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 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

On September 16, 2024, the CPUC issued a final decision on interim rate that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

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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 $74 million and $89 million as of December 31, 2024 and December 31, 2023, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.

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 Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2024		December 31, 2023
Topock natural gas compressor station	$	294	$	276
Hinkley natural gas compressor station	97		104
Former MGP sites owned by the Utility or third parties (1)	782		809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	76		107
Fossil fuel-fired generation facilities and sites (3)	18		19
Total environmental remediation liability	$	1,267	$	1,315

(1) Primarily driven by the following sites: San Francisco Beach Street, 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 EPA 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, 2024, 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, 2024, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

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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. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $211 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’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 action to meet interim cleanup targets. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $123 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. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $637 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. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 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. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $16 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 European Mutual Association for Nuclear Insurance (“EMANI”), covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

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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 DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident (including terrorism and cybersecurity) and $2.5 billion per non-nuclear incident for DCPP. For Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. These coverage amounts are shared by all NEIL members. EMANI shares losses with NEIL as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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 $42 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $500 million for DCPP. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 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 $500 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, 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, 2024:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Natural Gas		Other (1)		Total
2025	$	2,010	$	910	$	443	$	354	$	3,717
2026	1,952		866		348		162		3,328
2027	1,896		800		190		284		3,170
2028	1,875		800		103		141		2,919
2029	1,831		716		92		43		2,682
Thereafter	14,229		2,730		41		5		17,005
Total purchase commitments	$	23,793	$	6,822	$	1,217	$	989	$	32,821

(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, qualifying facilities (“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.

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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 2025 and 2045.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement 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 2025 and 2044.

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, 2024, QF contracts in operation expire at various dates between 2025 and 2042.  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 $2.1 billion in 2024, $2.4 billion in 2023, and $2.8 billion in 2022.

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 along with a facility associated with a third party tolling agreement.  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 2025 and 2042.  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 $0.8 billion in 2024, $2.5 billion in 2023, and $2.4 billion in 2022.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2025 and 2030 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 $294 million in 2024, $180 million in 2023, and $44 million in 2022.

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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 2025 and 2058, as well as other multi-year agreements.  At December 31, 2024, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2025	$	84
2026	44
2027	47
2028	37
2029	34
Thereafter	333
Total minimum payments	$	579

Payments for other commitments were $105 million in 2024, $106 million in 2023, and $63 million in 2022.  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 $650 million is to be made in 2025. If the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution of up to $775 million in 2040. The Utility also will share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

Additionally, the Utility agreed to purchase the Lakeside Building for $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. See “Oakland Headquarters Lease and Purchase” in Note 2 above.

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, 2024, 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, 2024.

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, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

165

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, 2024 and 2023, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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 12, 2025, 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 2, 3 and 14 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas and Electric Company, follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utility Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. Pacific Gas and Electric Company 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. Pacific Gas and Electric Company 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.

166

We identified the impact of rate regulation, specifically costs subject to cost recovery proceedings that have not yet been approved, 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. 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.

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 included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery of costs deferred as regulatory assets in future rates; 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 subject to cost recovery proceedings that have not yet been approved for recovery, meet the definition of a regulatory asset 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 Pacific Gas and Electric Company 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 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.

•We inspected Pacific Gas and Electric Company’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact Pacific Gas and Electric Company’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.

•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained from our procedures performed.

Wildfire-Related Contingencies and Recoveries—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas and Electric Company, has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2021 Dixie fire and 2022 Mosquito fire as of December 31, 2024. The loss contingencies represent the lower end of the range of reasonably possible losses in connection with each of the fires. Pacific Gas and Electric Company has also recorded estimated recoveries, inclusive of the Wildfire Expense Memorandum Account (“WEMA”), included within Noncurrent Regulatory Assets, and the Wildfire Fund Receivable, within Accounts Receivable—Other and Other Noncurrent Assets

We identified wildfire-related contingencies and related-recoveries, specifically the WEMA, 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 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.

167

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) Pacific Gas and Electric 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 Pacific Gas and Electric Company’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire, 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 by reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management 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 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.

•We read the legal letters from Pacific Gas and Electric 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 Pacific Gas and Electric Company’s disclosures were appropriate and consistent with the information obtained from our procedures performed.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 12, 2025

We have served as the Company’s auditor since 1999.

168

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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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 12, 2025, 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 2, 3 and 14 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 Utility 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.

169

We identified the impact of rate regulation, specifically costs subject to cost recovery proceedings that have not yet been approved, 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. 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.

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 included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery of costs deferred as regulatory assets in future rates; 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 subject to cost recovery proceedings that have not yet been approved for recovery, meet the definition of a regulatory asset 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 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.

•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.

•We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained from our procedures performed.

Wildfire-Related Contingencies and Recoveries—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2021 Dixie fire and 2022 Mosquito fire as of December 31, 2024. The loss contingencies represent the lower end of the range of reasonably possible losses in connection with each of the fires. The Utility has also recorded estimated recoveries, inclusive of the Wildfire Expense Memorandum Account (“WEMA”), included within Noncurrent Regulatory Assets, and the Wildfire Fund Receivable, within Accounts Receivable - Other and Other Noncurrent Assets.

We identified wildfire-related contingencies and related-recoveries, specifically the WEMA, 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 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.

170

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, 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 by reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management 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 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.

•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 from our procedures performed.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 12, 2025

We have served as the Utility’s auditor since 1999.

171

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, 2024, 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, 2024, 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, 2024, of the Company and our report dated February 12, 2025, 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 12, 2025

172

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, 2024, 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, 2024, 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, 2024, of the Utility and our report dated February 12, 2025, 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 12, 2025

173

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, 2024, 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 Exchange 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 2024 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, 2024, 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, 2024 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

On November 14, 2024, Kerry W. Cooper, who serves as the Chair of the Board of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of up to 6,800 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of December 16, 2025 or the execution of the sale of all 6,800 shares.

On November 15, 2024, Carla J. Peterman, who serves as the Executive Vice President, Corporate Affairs and Chief Sustainability Officer of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of an indeterminate number of shares of PG&E Corporation common stock. The number of shares that may be sold under this Rule 10b5-1 trading arrangement will vary based on the number of shares that Ms. Peterman receives when her performance share units (“PSUs”) vest. The maximum number of shares to be sold will be reduced by shares withheld to satisfy tax withholding obligations that arise in connection with the vesting and settlement. The trading arrangement will terminate on the earlier of June 27, 2025 or the execution of the sale of all covered shares.

On November 18, 2024, Marlene M. Santos, who serves as the Executive Vice President and Chief Customer and Enterprise Solutions Officer of the Utility, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of an indeterminate number of shares of PG&E Corporation common stock. The number of shares that may be sold under this Rule 10b5-1 trading arrangement will vary based on the number of shares that Ms. Santos receives when her PSUs vest. The maximum number of shares to be sold will be reduced by shares withheld to satisfy tax withholding obligations that arise in connection with the vesting and settlement. The trading arrangement will terminate on the earlier of June 27, 2025 or the execution of the sale of all covered shares.

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Certain officers have made elections to participate in, and are participating in, the PG&E Corporation Retirement Savings Plan (the 401(k) plan), which includes a PG&E Corporation Common Stock Fund investment option, and non-qualified deferred compensation plans, which may have a similar option and are described in PG&E Corporation’s and the Utility’s joint proxy statement. Also, certain officers have made, and may from time to time make, elections to have shares withheld to cover withholding taxes upon the vesting of restricted stock units or performance share units, or to pay the exercise price and withholding taxes for stock options, which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

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 2024 Form 10-K.

PG&E Corporation and the Utility have adopted insider trading policies and procedures governing the purchase, sale, and/or other dispositions of their securities by directors, officers, and employees. PG&E Corporation and the Utility have a policy of not issuing or purchasing securities while in possession of material nonpublic information but do not have written procedures for the repurchase of their securities. PG&E Corporation and the Utility believe their insider trading policies and procedures are reasonably designed to promote compliance with insider trading laws, rules, and regulations, and applicable listing standards. A copy of the insider trading policy is filed as Exhibit 19 to this Form 10-K.

Other information required by this Item 10 will be included in the Joint Proxy Statement relating to the 2025 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 “Delinquent Section 16(a) Reports,”) and “User Guide” (under the subheading “2025 Annual Meetings,”) which information is incorporated herein by reference.

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

PG&E Corporation and the Utility have adopted the following documents:

•A Code of Conduct applicable to all officers and employees;

•A Code of Conduct applicable to directors;

•A Code of Conduct applicable to suppliers and contractors;

•Corporate Governance Guidelines (separate guidelines for PG&E Corporation and the Utility); and

•Charters for committees of the Board, including charters for the Audit Committees, the PG&E Corporation Sustainability and Governance Committee, the PG&E Corporation Finance and Innovation Committee and the PG&E Corporation People and Compensation Committee.

Each of these documents is available on PG&E Corporation’s website at https://www.pgecorp.com/about/corporate-governance.html or https://www.pgecorp.com/about/compliance-and-ethics.html.

Any amendment to or waiver from the Code of Conduct that applies to executive officers or directors will be posted on the website.

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 - 2024,” “Grants of Plan-Based Awards in 2024,” “Outstanding Equity Awards at Fiscal Year End - 2024,” “Option Exercises and Stock Vested during 2024,” “Pension Benefits - 2024,” “Non-Qualified Deferred Compensation - 2024,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability,” “Compensation of Non-Employee Directors,” and “Principal Executive Officers’ (PEO) Pay Ratio - 2024,” in the Joint Proxy Statement relating to the 2025 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 2025 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, 2024 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	22,729,405	(1)	$	41.27	(2)	55,900,800	(3)
Equity compensation plans not approved by shareholders	—		—			—
Total equity compensation plans	22,729,405	(1)	$	41.27	(2)	55,900,800	(3)

(1) Includes 161 phantom stock units, 9,541,306 restricted stock units and 12,443,975 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 for operational and financial metrics or, for performance shares granted in 2022, amounts reflect the estimated payout percentage of 110% for performance shares using operational and financial metrics, and 200% of target for the total shareholder return metric. The actual number of shares issued can range from zero percent to 200% of target depending on achievement of performance objectives. 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 743,963 options outstanding as of December 31, 2024.

(3) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, 2024. 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 6 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 Person Transactions,” “Independence,” and “Committee Membership Requirements” in the Joint Proxy Statement relating to the 2025 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 2025 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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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, 2024, 2023, and 2022 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2024 and 2023 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2024, 2023, and 2022 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2024, 2023, and 2022 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:

Consolidated Financial Information of PG&E Corporation (“Parent”) as of December 31, 2024 and 2023 and for the Years Ended December 31, 2024, 2023, and 2022.

Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2024, 2023, and 2022.

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 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2022 (File No. 1-12609), Exhibit 3.1)
3.2	Certificate of Determination of 6.000% Series A Mandatory Convertible Preferred Stock of PG&E Corporation, filed with the Secretary of State of the State of California and effective as of December 5, 2024 (incorporated by reference to PG&E Corporation’s Form 8-K dated December 2, 2024 (File No. 1-12609) , Exhibit 3.1)
3.3	Bylaws of PG&E Corporation, Amended and Restated as of December 12, 2024 (incorporated by reference to PG&E Corporation’s Form 8-K dated December 12, 2024 (File No. 1-12609), Exhibit 3.1)
3.4	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)

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3.5	Bylaws of Pacific Gas and Electric Company, Amended and Restated as of December 12, 2024 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 12, 2024 (File No. 1-2348), Exhibit 3.2)
4.1 (a)	Description of PG&E Corporation’s Securities - Common Stock and Preferred Stock
4.1 (b)	Description of Pacific Gas and Electric Company’s Securities - Preferred Stock
4.1 (c)	Form of Certificate for 6.000% Series A Mandatory Convertible Preferred Stock (included within Exhibit 3.2 above) (incorporated by reference to PG&E Corporation’s Form 8-K dated December 2, 2024 (File No. 1-2609), Exhibit 4.1)
4.2	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004 (as supplemented) 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)
4.2.1	Sixteenth Supplemental Indenture, dated as of December 1, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.2.2	Seventeenth Supplemental Indenture, dated as of April 16, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.2.3	Eighteenth Supplemental Indenture, dated as of August 16, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.2.4	Nineteenth Supplemental Indenture, dated as of June 14, 2013 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
4.2.5	Twenty-First Supplemental Indenture, dated as of February 21, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 1-2348), Exhibit 4.1)
4.2.6	Twenty-Third Supplemental Indenture, dated as of August 18, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)
4.2.7	Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)
4.2.8	Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.2.9	Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.2.10	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.2.11	Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.2.12	Twenty-Ninth Supplemental Indenture, dated as of March 10, 2017 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 10, 2017 (File No. 1-2348), Exhibit 4.1)
4.2.13	Thirtieth Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.3)
4.3	Indenture, dated as of November 29, 2017, 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 November 29, 2017 (File No. 1-2348), Exhibit 4.1)
4.3.1	First Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.4)
4.4	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)

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4.4.1	First Supplemental Indenture, dated as of August 6, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.2)
4.4.2	Second Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 2, 2020 (File No. 1-2348), Exhibit 4.5)
4.5	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)
4.5.1	First Supplemental Indenture, dated as of June 19, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.2)
4.5.2	Second Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.6)
4.5.3	Third Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.1)
4.5.4	Fourth Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.2)
4.5.5	Fifth Supplemental Indenture, dated as of July 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.7)
4.5.6	Sixth Supplemental Indenture, dated as of August 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-2348), Exhibit 4.15)
4.5.7	Eighth Supplemental Indenture, dated as of March 11, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 8, 2021 (File No. 1-2348), Exhibit 4.1)
4.5.8	Ninth Supplemental Indenture, dated as of June 3, 2021, to the Indenture of Mortgage (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 12348), Exhibit 4.1)
4.5.9	Tenth Supplemental Indenture, dated as of June 22, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 4.1)
4.5.10	Eleventh Supplemental Indenture, dated as of October 29, 2021 (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)
4.5.11	Twelfth Supplemental Indenture, dated as of November 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 10, 2021 (File No. 1-2348), Exhibit 4.1)
4.5.12	Thirteenth Supplemental Indenture, dated as of February 18, 2022 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 16, 2022 (File No. 1-2348), Exhibit 4.1)
4.5.13	Fourteenth Supplemental Indenture, dated as of April 4, 2022 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 4, 2022 (File No. 1-2348), Exhibit 4.1)
4.5.14	Fifteenth Supplemental Indenture, dated as of April 20, 2022 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 4.1)
4.5.15	Sixteenth Supplemental Indenture, dated as of June 8, 2022 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 6, 2022 (File No. 1-2348), Exhibit 4.1)
4.5.16	Seventeenth Supplemental Indenture, dated as of October 4, 2022 (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)
4.5.17	Eighteenth Supplemental Indenture, dated as of January 6, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 4, 2023 (File No. 1-2348), Exhibit 4.1)
4.5.18	Nineteenth Supplemental Indenture, dated as of March 30, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 28, 2023 (File No. 1-2348), Exhibit 4.1)
4.5.19	Twentieth Supplemental Indenture, dated as of June 5, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2023 (File No. 1-2348), Exhibit 4.1)

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4.5.20	Twenty-First Supplemental Indenture, dated as of November 8, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2023 (File No. 1-2348), Exhibit 4.1)
4.5.21	Twenty-Second Supplemental Indenture, dated as of November 15, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 15, 2023 (File No. 1-2348), Exhibit 4.1)
4.5.22	Twenty-Third Supplemental Indenture, dated as of December 21, 2023 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2023 (File No. 1-2348, Exhibit 4.5.22)
4.5.23	Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 26, 2024 (File No. 1-2348), Exhibit 4.1)
4.5.24	Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 3, 2024 (File No. 1-2348), Exhibit 4.1)
4.5.25	Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 17, 2025 (File No. 1-2348), Exhibit 4.1)
4.6	Note Purchase Agreement dated January 17, 2025, among Pacific Gas and Electric Company, the U.S. Department of Energy, acting by and through the Secretary of Energy, and the Federal Financing Bank (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 17, 2025 (File No. 1-2348), Exhibit 4.2)
4.6.1	Future Advance Promissory Note dated January 17, 2025, made by Pacific Gas and Electric Company to the Federal Financing Bank (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 17, 2025 (File No. 1-2348), Exhibit 4.3)
4.7	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)
4.7.1	First Supplemental Indenture, dated as of June 23, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.2)
4.8	Indenture, dated as of December 4, 2023, among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., as trustee and JPMorgan Chase Bank, N.A., as collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated December 4, 2023 (File No. 1-12609), Exhibit 4.1)
4.9	Subordinated Note Indenture, dated as of September 11, 2024, 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 September 9, 2024 (File No. 1-12609), Exhibit 4.1)
4.9.1	First Supplemental Indenture, dated as of September 11, 2024 (incorporated by reference to PG&E Corporation’s Form 8-K dated September 9, 2024 (File No. 1-12609), Exhibit 4.2)
10.1	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)
10.2	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)
10.3	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 PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.3)

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10.3.1	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, JPMorgan 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)
10.3.2	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)
10.3.3	Amendment No. 3 to Credit Agreement, dated as of June 22, 2023, 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., administrative agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 22, 2023 (File No. 1-12609), Exhibit 10.1)
10.3.4	Amendment No. 4 to Credit Agreement, dated as of July 25, 2024, 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, 2024 (File No. 1-12609), Exhibit 10.6)
10.4	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 part 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)
10.5	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)
10.5.1	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, 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 22, 2021 (File No. 1-2348), Exhibit 10.2)
10.5.2	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)
10.5.3	Amendment No. 3 to Credit Agreement, dated as of June 22, 2023, among Pacific Gas and Electric Company, 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 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2023 (File No. 1-2348), Exhibit 10.2)
10.5.4	Amendment No. 4 to Credit Agreement, dated as of July 25, 2024, among Pacific Gas and Electric Company, the lenders party thereto, Citibank, N.A., as administrative agent and designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2024 (File No. 1-12609), Exhibit 10.5)
10.6	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)
10.6.1	Amendment No. 1 to 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 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2022 (File No. 1-2348) Exhibit (10.37)
10.6.2	Amendment No. 2 to Credit Agreement, dated as of April 18, 2023, among Pacific Gas and Electric Company, the several lenders from time to time party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2023 (File No. 1-2348) Exhibit 10.3)
10.6.3	Amendment No. 3 to Credit Agreement, dated as of April 16, 2024, among Pacific Gas and Electric Company, the lenders party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2024 (File No. 1-2348) Exhibit 10.1)

182

10.7	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 Pacific Gas and Electric Company’s Form 8-K dated October 5, 2020 (File No. 1-2348), Exhibit 10.1)
10.7.1	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 Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2020 (File No. 1-2348), Exhibit 10.75)
10.7.2	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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-2348), Exhibit 10.2)
10.7.3	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)
10.8	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 Pacific Gas and Electric Company’s Form 8-K dated October 5, 2020 (File No. 1-2348), Exhibit 10.2)
10.8.1	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 Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2020 (File No. 1-2348), Exhibit 10.77)
10.8.2	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 Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2020 (File No. 1-2348), Exhibit 10.78)
10.8.3	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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-2348), Exhibit 10.2)
10.8.4	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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-2348), Exhibit 10.3)
10.8.5	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)

183

10.8.6	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)
10.8.7	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)
10.8.8	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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-2348), Exhibit 10.7)
10.8.9	Amendment No. 9 to Receivables Financing Agreement, dated as of June 9, 2023, 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, 2023 (File No. 1-2348), Exhibit 10.3)
10.8.10	Amendment No. 10 to Receivables Financing Agreement, dated as of December 8, 2023, 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, 2024 (File No. 1-2348), Exhibit 10.2)
10.8.11	Amendment No. 11 to Receivables Financing Agreement, dated as of March 28, 2024, 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, 2024 (File No. 1-2348), Exhibit 10.3)
10.8.12	Amendment No. 12 to Receivables Financing Agreement, dated as of June 26, 2024, 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, 2024 (File No. 1-2348), Exhibit 10.2)
10.9	Pledge Agreement, dated as of October 5, 2020, between Pacific Gas and Electric Company and MUFG Bank, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 5, 2020 (File No. 1-2348), Exhibit 4.1)
10.10	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 Pacific Gas and Electric Company’s Form 8-K dated October 5, 2020 (File No. 1-2348), Exhibit 10.3)
10.10.1	Update to Schedule 1 to Collection Account Intercreditor Agreement, dated as of March 28, 2024, among Pacific Gas and Electric Company, PG&E Recovery Funding LLC, PG&E Wildfire Recovery Funding LLC, Citibank, N.A., MUFG Bank Ltd., and The Bank of New York Mellon Trust Company, N.A. (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2024 (File No. 1-2348) Exhibit 10.4)
10.10.2	Joinder Agreement to Collection Account Intercreditor Agreement, dated as of August 1, 2024, among Pacific Gas and Electric Company, Citibank, N.A., in its role as collection account agent and PG&E Recovery Funding LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 1, 2024 (File No. 1-2348), Exhibit 10.4)
10.11	Office Lease, dated as of October 23, 2020, between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-2348), Exhibit 10.12)
10.11.1	First Amendment to Office Lease, dated as of June 14, 2023, by and between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2023 (File No. 1-2348), Exhibit 10.6)

184

10.11.2		Amendment to Office Lease, dated as of July 11, 2023, by and between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2023 (File No. 1-2348), Exhibit 10.7)
10.12		Loan Guarantee Agreement, dated as of January 17, 2025, between Pacific Gas and Electric Company and the U.S. Department of Energy, acting by and through the Secretary of Energy (redacted) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 17, 2025 (File No. 1-2348), Exhibit 10.1)
10.13	*	Offer Letter between Pacific Gas and Electric Company and Kaled Awada, dated December 9, 2023 (redacted) (incorporated by reference to Pacific Gas and Electric’s Form 10-K for the year ended December 31, 2023 (File No. 1-2348), Exhibit 10.25)
10.14	*	Offer Letter between PG&E Corporation and Carolyn Burke, dated as of March 15, 2023 (redacted) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2023 (File No. 1-12609), Exhibit 10.4)
10.15	*	Retention Letter Agreement, dated as of February 20, 2024, between PG&E Corporation and Carla J. Peterman (redacted) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2024 (File No. 1-12609), Exhibit 10.5)
10.16	*	Retention Letter Agreement, dated as of February 20, 2024, between PG&E Corporation and John R. Simon (redacted) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2024 (File No. 1-12609), Exhibit 10.6)
10.17	*	Offer Letter, between PG&E Corporation and Patricia K. Poppe, effective November 13, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated November 18, 2020 (File No. 1-12609), Exhibit 10.1)
10.18	*	Amendment to Offer Letter, between PG&E Corporation and Patricia K. Poppe, dated as of November 29, 2024 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K dated November 29, 2024 (File No. 1-2609) (File No. 1-2348), Exhibit 10.1)
10.19	*	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of September 12, 2023 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2023 (File No. 1-12609), Exhibit 10.5)
10.20	*	PG&E Corporation Supplemental Retirement Savings Plan, as amended effective as of September 12, 2023, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2023 (File No. 1-12609), Exhibit 10.2)
10.21	*	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective as of May 14, 2024 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2024 (File No. 1-12609), Exhibit 10.4)
10.22	*	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 12, 2023 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2023 (File No. 1-12609), Exhibit 10.4)
10.23	*	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of September 12, 2023 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2023 (File No. 1-12609), Exhibit 10.30)
10.24	*	PG&E Corporation Short-Term Incentive Plan, as amended effective as of May 16, 2023 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2023 (File No. 1-12609), Exhibit 10.8)
10.25	*	Pacific Gas and Electric Company Officer Relocation Guide, effective as of May 1, 2022
10.26	*	Postretirement Life Insurance Plan of Pacific Gas and Electric Company, as amended and restated as of 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)
10.27	*	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective as of 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)
10.28	*	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective as of February 16, 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)

185

10.29	*	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective as of January 1, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2020 (File No. 1-2348), Exhibit 10.100)
10.30	*	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective as of January 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2022 (File No. 1-12609), Exhibit 10.77)
10.31	*	PG&E Corporation 2014 Long-Term Incentive Plan (as adopted effective May 12, 2014 and as last amended effective as of July 1, 2020) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 112609), Exhibit 10.40)
10.32	*	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)
10.33	*	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)
10.34	*	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)
10.35	*	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)
10.36	*	Form of Restricted Stock Unit Agreement for 2023 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, 2023 (File No. 1-12609), Exhibit 10.9)
10.37	*	Form of Restricted Stock Unit Agreement for 2024 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, 2024 (File No. 1-12609), Exhibit 10.5)
10.38	*	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)
10.39	*	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)
10.40	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Restricted Stock Unit Award, as amended effective 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 10.8)
10.41	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Program-Specific Retention Stock Unit Award Agreement, effective September 17, 2024 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2024 (File No. 1-12609), Exhibit 10.7)
10.42	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Restricted Stock Unit Award, as amended effective 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. 112609), Exhibit 10.9)
10.43	*	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)
10.44	*	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)
10.45	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Performance Share Unit Award, as amended effective 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. 112609), Exhibit 10.10)

186

10.46	*	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)
10.47	*	Form of Consent to Amend Award Agreement under the 2014 PG&E Corporation Long-Term Incentive Plan and/or 2021 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2023 (File No. 112609), Exhibit 10.7)
10.48	*	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
10.49	*	PG&E Corporation 2010 Executive Stock Ownership Guidelines, as amended effective as of December 11, 2024
10.50	*	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)
10.51	*	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)
10.52	*	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, as amended 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)
10.53	*	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)
10.54	*	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)
10.55	*	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of 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)
10.56	*	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)
10.57	*	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)
10.58	*	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)
10.59	*	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)
19		Insider Trading Standard
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 Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

187

31.2		Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1	**	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2	**	Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
97.1		PG&E Corporation and Pacific Gas and Electric Company Dodd-Frank Clawback Policy (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2023 (File No. 1-12609), Exhibit 97.1)
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
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)
*		Management contract or compensatory agreement
**		Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

188

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, 2024 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/ SUMEET SINGH
	Patricia K. Poppe		Sumeet Singh
By:	Chief Executive Officer	By:	Executive Vice President, Operations and Chief Operating Officer
Date:	February 12, 2025	Date:	February 12, 2025
			/s/ MARLENE M. SANTOS
			Marlene M. Santos
		By:	Executive Vice President and Chief Customer and Enterprise Solutions Officer
		Date:	February 12, 2025
			/s/ JASON M. GLICKMAN
			Jason M. Glickman
		By:	Executive Vice President, Engineering, Planning, and Strategy
		Date:	February 12, 2025

Signature	Title	Date
A.  Principal Executive Officers
/s/ PATRICIA K. POPPE	Chief Executive Officer	February 12, 2025
Patricia K. Poppe	(PG&E Corporation)

/s/ SUMEET SINGH	Executive Vice President, Operations and Chief Operating Officer	February 12, 2025
Sumeet Singh	(Pacific Gas and Electric Company)

189

/s/ MARLENE M. SANTOS	Executive Vice President and Chief Customer and Enterprise Solutions Officer	February 12, 2025
Marlene M. Santos	(Pacific Gas and Electric Company)

/s/ JASON M. GLICKMAN	Executive Vice President, Engineering, Planning, and Strategy	February 12, 2025
Jason M. Glickman	(Pacific Gas and Electric Company)

B. Principal Financial Officers
/s/ CAROLYN J. BURKE	Executive Vice President and Chief Financial Officer	February 12, 2025
Carolyn J. Burke	(PG&E Corporation)

/s/ STEPHANIE N. WILLIAMS	Vice President and Controller (PG&E Corporation)	February 12, 2025
Stephanie N. Williams	Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company)

C. Principal Accounting Officer
/s/ STEPHANIE N. WILLIAMS	Vice President and Controller (PG&E Corporation)	February 12, 2025
Stephanie N. Williams	Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company)

	D.  Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted)
*	/s/ RAJAT BAHRI	Director	February 12, 2025
	Rajat Bahri

*	/s/ CHERYL F. CAMPBELL	Director	February 12, 2025
	Cheryl F. Campbell	Chair of the Board (Pacific Gas and Electric Company)

*	/s/ EDWARD G. CANNIZZARO	Director	February 12, 2025
	Edward G. Cannizzaro

*	/s/ KERRY W. COOPER	Director	February 12, 2025
	Kerry W. Cooper	Chair of the Board (PG&E Corporation)

*	/s/ JESSICA L. DENECOUR	Director	February 12, 2025
	Jessica L. Denecour

*	/s/ MARK E. FERGUSON III	Director	February 12, 2025
	Mark E. Ferguson III

190

*	/s/ W. CRAIG FUGATE	Director	February 12, 2025
	W. Craig Fugate

*	/s/ ARNO L. HARRIS	Director	February 12, 2025
	Arno L. Harris

*	/s/ CARLOS M. HERNANDEZ	Director	February 12, 2025
	Carlos M. Hernandez

*	/s/ MICHAEL R. NIGGLI	Director	February 12, 2025
	Michael R. Niggli

*	/s/ PATRICIA K. POPPE	Director	February 12, 2025
	Patricia K. Poppe

*	/s/ WILLIAM L. SMITH	Director	February 12, 2025
	William L. Smith

*	/s/ BENJAMIN F. WILSON	Director	February 12, 2025
	Benjamin F. Wilson

*	/s/ SUMEET SINGH	Director (Pacific Gas and Electric Company)	February 12, 2025
	Sumeet Singh

*By:	/s/ JOHN R. SIMON	February 12, 2025
	John R. Simon, Attorney-in-Fact

191

PG&E CORPORATION

SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2024		2023		2022
Administrative service revenue	$	146	$	154	$	109
Operating expenses	(167)		(165)		(193)
Interest income	15		13		3
Interest expense	(270)		(365)		(261)
Other income (expense)	(17)		(21)		(201)
Equity in earnings of subsidiaries	2,697		2,530		2,154
Income Before Income Taxes	2,404		2,146		1,611
Income tax benefit	(94)		(96)		(132)
Net Income	$	2,498	$	2,242	$	1,743
Preferred stock dividend requirement	23		—		—
Income Available for Common Shareholders	$	2,475	$	2,242	$	1,743
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)		(16)		21
Net unrealized gain on available-for-sale securities (net of taxes of $0, $0, and $0, respectively)	1		—		—
Total other comprehensive income (loss)	(6)		(16)		21
Comprehensive Income	$	2,469	$	2,226	$	1,764
Weighted Average Common Shares Outstanding, Basic	2,141		2,064		2,235
Weighted Average Common Shares Outstanding, Diluted	2,147		2,138		2,380
Net Earnings Per Common Share, Basic	$	1.16	$	1.09	$	0.78
Net Earnings Per Common Share, Diluted	$	1.15	$	1.05	$	0.73

192

PG&E CORPORATION

SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONSOLIDATED BALANCE SHEETS

	Balance at December 31,
(in millions)	2024		2023
ASSETS
Current Assets
Cash and cash equivalents	$	235	$	192
Restricted cash and restricted cash equivalents	1		3
Advances to affiliates	13		24
Income taxes receivable	2		2
Other current assets	—		1
Total current assets	251		222
Other Noncurrent Assets
Investments in subsidiaries	42,829		36,804
Other investments	175		167
Deferred income taxes	633		539
Total other noncurrent assets	43,637		37,510
TOTAL ASSETS	$	43,888	$	37,732
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable – other	36		58
Income taxes payable	1		1
Other current liabilities	420		363
Total current liabilities	457		422
Noncurrent Liabilities
Long-term debt	5,612		4,599
Other noncurrent liabilities	141		141
Total noncurrent liabilities	5,753		4,740
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		—
Common stock	39,086		37,906
Reinvested earnings	(2,966)		(5,322)
Accumulated other comprehensive loss	(21)		(14)
Total shareholders’ equity	37,678		32,570
TOTAL LIABILITIES AND EQUITY	$	43,888	$	37,732

193

PG&E CORPORATION

SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2024		2023		2022
Cash Flows from Operating Activities:
Net income	$	2,498	$	2,242	$	1,743
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	53		4		95
Equity in earnings of subsidiaries	(2,699)		(2,530)		(2,160)
Deferred income taxes and tax credits, net	(94)		(116)		(126)
Current income taxes payable	—		9		—
Other	9		40		339
Net cash used in operating activities	(233)		(351)		(109)
Cash Flows From Investing Activities:
Investment in subsidiaries	(5,360)		(1,290)		(994)
Dividends received from subsidiaries (1)	2,025		1,775		1,275
Net cash provided by (used in) investing activities	(3,335)		485		281
Cash Flows From Financing Activities:
Repayments under term loan credit facilities	(500)		(2,181)		—
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates	—		2,123		—
Repayment of long-term debt	—		—		(28)
Repayments of intercompany note from the Utility	—		—		(145)
Proceeds from issuance of long-term debt, net of premium and    issuance costs of $4, $0, and $0 at respective dates	1,496		—		—
Common stock issued	1,128		—		—
Mandatory convertible preferred stock issued	1,579		—		—
Common stock dividend paid	(86)		—		—
Other	(8)		(6)		—
Net cash provided by (used in) financing activities	3,609		(64)		(173)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	41		70		(1)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	195		125		126
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	236	$	195	$	125
Less: Restricted cash and restricted cash equivalents	(1)		(3)		—
Cash and cash equivalents at December 31	$	235	$	192	$	125
Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(215)	$	(309)	$	(233)
Supplemental disclosures of noncash investing and financing activities
Changes to PG&E Corporation common stock and treasury stock in connection     with the share exchange with the Fire Victim Trust	$	—	$	(2,517)	$	(2,337)
Common stock dividends declared but not yet paid	55		21		—
Mandatory convertible preferred stock dividends declared but not yet paid	23		—		—

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

194

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2024, 2023, and 2022

(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:
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166

(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.

195

PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2024, 2023, and 2022

(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:
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166

(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.

196

EX-4.1A

EXHIBIT 4.1(a)

DESCRIPTION OF PG&E CORPORATION’S SECURITIES REGISTERED UNDER SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

Capital Stock Registered under Section 12 of the Securities Exchange Act of 1934:

•Common Stock, no par value ( the “Common Stock”)

•6.000% Series A Mandatory Convertible Preferred Stock (the “Mandatory Convertible Preferred Stock”)

The following description of PG&E Corporation’s capital 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 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 December 12, 2024 (the “Bylaws”), and, with respect to the Mandatory Convertible Preferred Stock, the Certificate of Determination (as defined below) filed December 5, 2024, 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 PG&E Corporation and not to any of its direct or indirect subsidiaries or affiliates except as expressly provided.

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, 2024, there were approximately 2,671,317,126 shares of our Common Stock, no par value, outstanding, 32,200,000 shares of our Mandatory Convertible Preferred Stock outstanding, and no other shares of preferred stock outstanding. All outstanding shares of our capital stock are fully paid and nonassessable.

Description of the Common Stock

General

We may issue our capital stock (including Common Stock and preferred 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.

Ownership Restrictions

Holders of our Common Stock may not directly or indirectly acquire more than 4.75% of the combined value of our outstanding stock, including, for the avoidance of doubt, Common Stock, preferred stock, and other interest designated as our “stock” by the Board of Directors as disclosed in an SEC filing by us.

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

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 the Mandatory Convertible Preferred Stock and 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. See “Description of Mandatory Convertible Preferred Stock” below for a description of the terms of the Mandatory Convertible Preferred Stock, which include limitations and qualifications on the rights of holders of the Common 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.

Description of the Mandatory Convertible Preferred Stock

Ranking

The Mandatory Convertible Preferred Stock, with respect to dividend rights and/or distribution rights upon our liquidation, winding-up or dissolution, as applicable, will rank:

•senior to our Common Stock and each other class or series of our capital stock established after the first original issue date of shares of the Mandatory Convertible Preferred Stock (which we refer to as the “Initial Issue Date”), the terms of which do not expressly provide that such class or series ranks either (x) senior to the Mandatory Convertible Preferred Stock as to dividend rights and distribution rights upon our liquidation, winding-up or dissolution or (y) on parity with the Mandatory Convertible Preferred Stock as to

dividend rights and distribution rights upon our liquidation, winding-up or dissolution (which we refer to collectively as “Junior Stock”);

•on parity with any class or series of our capital stock established after the Initial Issue Date, the terms of which expressly provide that such class or serieswill rank on parity with the Mandatory Convertible Preferred Stock as to dividend rights and distribution rights upon our liquidation, winding-up or dissolution (which we refer to collectively as “Parity Stock”);

•junior to each class or series of our capital stock established after the Initial Issue Date, the terms of which expressly provide that such class or series will rank senior to the Mandatory Convertible Preferred Stock as to dividend rights or distribution rights upon our liquidation, winding up or dissolution (which we refer to collectively as “Senior Stock”); and

•junior to our existing and future indebtedness and other liabilities.

In addition, with respect to dividend rights and distribution rights upon our liquidation, winding up or dissolution, the Mandatory Convertible Preferred Stock will be structurally subordinated to any existing and future indebtedness and other liabilities of each of our subsidiaries.

Dividend Rights

Dividends on the Mandatory Convertible Preferred Stock are payable quarterly on a cumulative basis when, as and if declared by the Board of Directors, or an authorized committee thereof, out of funds legally available for payment, at a rate of 6.00% of the liquidation preference of $50.00 per share of the Mandatory Convertible Preferred Stock per annum. We may, in our discretion, pay quarterly declared dividends in cash or, subject to certain limitations, in shares of our common stock or any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97% of the volume-weighted average price per share over the five-consecutive trading day period beginning on, and including, the sixth scheduled trading day prior to the applicable dividend payment date, except that in no event will the number of shares of common stock to be delivered per share of Mandatory Convertible Preferred Stock in connection with any declared dividend exceed a number equal to the total dividend payment per share divided by a floor price of $7.19, subject to certain anti-dilution adjustments.

So long as any share of the Mandatory Convertible Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on our common stock or any other class or series of Junior Stock, and no common stock or any other class or series of Junior Stock or Parity Stock shall be, directly or indirectly, purchased, redeemed or otherwise acquired for consideration by us or any of our subsidiaries unless, in each case, all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid in full in cash, shares of our common stock or a combination thereof, or a sufficient sum of cash or number of shares of our common stock has been set apart for the payment of such dividends, on all outstanding shares of the Mandatory Convertible Preferred Stock. The foregoing limitation shall not apply to: (i) any dividend or distribution payable in shares of common stock or other Junior Stock, together with cash in lieu of any fractional share, (ii) purchases, redemptions or other acquisitions of common stock or other Junior Stock or Parity Stock in connection with the administration of any benefit or other incentive plan, including any employment or compensation agreement, including, without limitation, (x) the forfeiture of unvested shares of restricted stock or share withholdings or other acquisitions or surrender of shares or derivative securities to which the holder may otherwise be entitled upon exercise, delivery or vesting of equity awards (whether in payment of applicable taxes, the exercise price or otherwise) and (y) the payment of cash in lieu of fractional shares; (iii) purchases or deemed purchases or acquisitions of fractional interests in shares of any of our common stock or other Junior Stock pursuant to the conversion or exchange provisions of such shares of other Junior Stock or any securities exchangeable for or convertible into shares of common stock or other Junior Stock; (iv) any dividends or distributions of rights or common stock or other Junior Stock in connection with a stockholders’ rights plan or any redemption or repurchase of rights pursuant to any stockholders’ rights plan; (v) purchases of common stock or other Junior Stock pursuant to a contractually binding requirement to buy common stock or other Junior Stock, including under a contractually binding stock repurchase plan, in each case, existing prior to the date of this prospectus supplement; (vi) the acquisition by us or any of our subsidiaries of record ownership in common stock or other Junior Stock or Parity Stock for the beneficial ownership of any other persons (other than us or any of our subsidiaries), including as trustees or custodians, and the payment of cash in lieu of fractional shares; (vii) the exchange or conversion of Junior Stock for or into other Junior Stock or of Parity Stock for or into other Parity Stock (with the same or lesser aggregate liquidation preference) or Junior Stock and the payment of cash in lieu of fractional shares; or (viii) the settlement of any convertible note hedge transactions or capped call transactions entered into in connection with the issuance, by us or any of our subsidiaries, of any debt securities that are convertible into, or exchangeable for, our common stock (or into or for any combination of cash and our common stock based on the value of our common stock), provided such convertible note hedge transactions or capped call transactions, as applicable, are on customary terms and were entered into either (a) before the Initial Issue Date or (b) in compliance with the foregoing provision.

Liquidation Preference

In the event of our voluntary or involuntary liquidation, winding-up or dissolution, each holder of the Mandatory Convertible Preferred Stock will be entitled to receive a liquidation preference in the amount of $50.00 per share of the Mandatory Convertible Preferred Stock (the “Liquidation Preference”), plus an amount (the “Liquidation Dividend Amount”) equal to accumulated and unpaid dividends on such shares, whether or not declared, to, but excluding, the date fixed for liquidation, winding-up or dissolution, such amount to be paid out of our assets legally available for distribution to our stockholders, after satisfaction of debt and other liabilities owed to our creditors and holders of shares of any Senior Stock and before any payment or distribution is made to holders of Junior Stock (including our common stock).

If, upon our voluntary or involuntary liquidation, winding-up or dissolution, the amounts payable with respect to (1) the Liquidation Preference plus the Liquidation Dividend Amount on the shares of the Mandatory Convertible Preferred Stock and (2) the liquidation preference of, and the amount of accumulated and unpaid dividends (to, but excluding, the date fixed for liquidation, winding-up or dissolution) on, all Parity Stock are not paid in full, the holders of Mandatory Convertible Preferred Stock and all holders of any such Parity Stock will share equally and ratably in any distribution of our assets in proportion to their respective liquidation preferences and amounts equal to the accumulated and unpaid dividends to which they are entitled.

After the payment to any holder of the Mandatory Convertible Preferred Stock of the full amount of the Liquidation Preference and the Liquidation Dividend Amount for such holder’s shares of the Mandatory Convertible Preferred Stock, such holder as such will have no right or claim to any of our remaining assets.

Neither the sale, lease nor exchange of all or substantially all of our assets or business (other than in connection with our liquidation, winding-up or dissolution), nor our merger or consolidation into or with any other person, will be deemed to be our voluntary or involuntary liquidation, winding-up or dissolution.

Ownership Restrictions

See “Description of Common Stock – Ownership Restrictions.”

Voting Rights

Holders of our Mandatory Convertible Preferred Stock do not have any voting rights or powers, except as described below and as specifically required by California law or by our Articles of Incorporation.

Whenever dividends on any shares of the Mandatory Convertible Preferred Stock have not been declared and paid for the equivalent of six or more dividend periods, whether or not for consecutive dividend periods, the authorized number of directors on our Board will, at the next annual meeting of stockholders or at a special meeting of stockholders, automatically be increased by two (or if such increase would exceed the maximum number of directors then permitted under the Articles of Incorporation, we shall take any action required to cause two authorized director seats to be vacant), and the holders of the Mandatory Convertible Preferred Stock, voting together as a single class with holders of any and all other series of Voting Preferred Stock (as defined below) then outstanding, will be entitled, at our next annual meeting of stockholders or at a special meeting of stockholders, if any, to vote for the election of a total of two additional members of our Board, subject to certain limitations.

As used herein, “Voting Preferred Stock” means any other class or series of our Parity Stock upon which like voting powers for the election of directors have been conferred and are exercisable.

So long as any shares of the Mandatory Convertible Preferred Stock are outstanding, we will not, without the affirmative vote or consent of the holders of record of at least two-thirds in voting power of the outstanding

shares of the Mandatory Convertible Preferred Stock and, solely with respect to clause (1) below, all other series of Voting Preferred Stock at the time outstanding and entitled to vote thereon, voting together as a single class:

1.    amend or alter the provisions of our Articles of Incorporation so as to authorize or create, or increase the authorized number of, any class or series of Senior Stock;

2.    amend, alter or repeal the provisions of our Articles of Incorporation or the Certificate of Determination governing the terms of the Mandatory Convertible Preferred Stock (the “Certificate of Determination”) so as to materially and adversely affect the special rights, preferences or voting powers of the Mandatory Convertible Preferred Stock; or

3.    consummate a binding share exchange or reclassification involving the shares of the Mandatory Convertible Preferred Stock, a merger or consolidation of us with or into another entity or a conversion of, domestication in or transfer of us to a foreign jurisdiction, unless, in each case: (i) the shares of the Mandatory Convertible Preferred Stock remain outstanding following the consummation of such binding

share exchange, reclassification, merger or consolidation or, in the case of (x) any such merger or consolidation with respect to which we are not the surviving or resulting entity (or in which the Mandatory Convertible Preferred Stock is otherwise exchanged or reclassified) or (y) any such conversion, domestication or transfer, are converted or reclassified into or exchanged for preference securities of the surviving or resulting entity, of the converted, domesticated or transferred entity or, in either case, such entity’s ultimate parent; and (ii) the shares of the Mandatory Convertible Preferred Stock that remain outstanding or such shares of preference securities, as the case may be, have such rights, preferences and voting powers that, taken as a whole, are not materially less favorable to the holders thereof than the rights, preferences and voting powers, taken as a whole, of the Mandatory Convertible Preferred Stock immediately prior to the consummation of such transaction, in each case, subject to certain exceptions.

In addition, in certain circumstances described in the Certificate of Determination, we may amend, alter, correct, supplement or repeal any of the terms of the Mandatory Convertible Preferred Stock without the vote or consent of the holders of the Mandatory Convertible Preferred Stock.

Mandatory Conversion

Unless earlier converted, each outstanding share of the Mandatory Convertible Preferred Stock will automatically convert on the mandatory conversion date of December 1, 2027, pursuant to the conversion procedures set forth in the Certificate of Determination. The number of shares of our Common Stock issuable upon conversion of each share of Mandatory Convertible Preferred Stock will be determined based on the volume-weighted average market value per share of our common stock over the 20-consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding the mandatory conversion date, subject to certain anti-dilution adjustments and certain adjustments in the event of any undeclared, accumulated and unpaid dividends. The following table illustrates the conversion rate per share of each series of Mandatory Convertible Preferred Stock, in each case subject to such adjustments:

Series A preferred stock
Greater than $25.6871 (which is the threshold appreciation price)	1.9465 shares (the minimum conversion rate, approximately equal to $50 divided by the threshold appreciation price)
Equal to or less than $25.6871 but greater than or equal to $20.5499	Between 1.9465 and 2.4331 shares, determined by dividing $50.00 by the applicable market value of our common stock
Less than $20.5499 (which is the initial price)	2.4331 shares (approximately equal to $50.00 divided by the initial price)

Conversion at the Option of the Holder

Generally, subject to the terms of the Mandatory Convertible Preferred Stock and pursuant to the conversion procedures set forth in the Certificate of Determination, at any time prior to December 1, 2027, holders may elect to convert each share of their preferred stock into shares of common stock at the minimum conversion rate (as it may be adjusted pursuant to certain anti dilution adjustments), plus certain additional shares of common stock if there are undeclared, accumulated and unpaid dividends on the preferred stock being converted.

In addition, if holders elect to convert any shares of Mandatory Convertible Preferred Stock during a specified period beginning on the effective date of a Fundamental Change, as defined in the Certificate of Determination, such shares of Mandatory Convertible Preferred Stock will be converted into shares of our common stock (or Units or Exchange Property as described in the Certificate of Designations) at a Fundamental Change Conversion Rate as set forth in such Certificate of Determination, and the holders will also be entitled to receive a Fundamental Change Dividend Make-Whole Amount and Accumulated Dividend Amount, in each case payable in cash or shares of common stock and as defined in such Certificate of Determination. For this purpose, a “Fundamental Change” will be deemed to have occurred upon (i) the consummation of (A) any recapitalization, reclassification or change of our common stock (other than changes resulting from a subdivision or combination or change in par value) as a result of which our common stock would be converted into, or exchanged for, stock, other securities, other property or assets (including cash or a combination thereof); (B) any consolidation, merger or other combination of us or binding share exchange pursuant to which our common stock will be converted into, or exchanged for, stock, other securities or other property or assets (including cash or a combination thereof); or (C) any sale, lease or other transfer or disposition in one transaction or a series of transactions of all or substantially all of the consolidated assets of ours and our subsidiaries taken as a whole, to any person other than one or more of our wholly-owned subsidiaries; (ii) any “person” or “group” (as such terms are used for purposes of Sections 13(d) and 14(d) of the Exchange Act, whether or not applicable), other than us, any of our wholly-owned subsidiaries or any of our or any of our wholly-owned subsidiaries’ employee benefit plans (or any person or entity acting solely in its capacity as trustee, agent or other fiduciary or administrator of any such plan), filing a Schedule TO or any schedule, form or report under the

Exchange Act disclosing that such person or group has become the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 50% of the total voting power in the aggregate of all classes of capital stock then outstanding entitled to vote generally in elections of our directors; or; or (iii) our common stock ceases to be listed or quoted for trading on the NYSE, the Nasdaq Global Select Market or the Nasdaq Global Market (or another U.S. national securities exchange or any of their respective successors).

These features of the Mandatory Convertible Preferred Stock could increase the cost of acquiring PG&E Corporation or otherwise discourage a third party from acquiring PG&E Corporation or removing incumbent management.

Other Rights

Our Mandatory Convertible Preferred Stock does not contain any sinking fund or redemption provisions. Holders of our Mandatory Convertible Preferred Stock are not entitled to preemptive rights to subscribe for or purchase any part of any new or additional issue of stock or securities convertible into stock.

Listing

Our Mandatory Convertible Preferred Stock is listed on the New York Stock Exchange under the symbol “PCG-PrX.”

Transfer Agent and Registrar

The transfer agent and registrar for our Mandatory Convertible Preferred Stock is EQ Shareowner Services.

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 4.1b)) 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.

EX-4.1B

EXHIBIT 4.1(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 December 12, 2024 (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% redeemable, series A (“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, 2024, 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 original 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-10.25

EXHIBIT 10.25

Officer Relocation Guide

Table of Contents

TABLE OF CONTENTS.......................................................................................................................1

GETTING STARTED............................................................................................................................1

Your Relocation Guide..............................................................................................................1

Important Notices......................................................................................................................1

Time off for Relocation Needs..................................................................................................1

ALTAIR WILL ADMINISTER YOUR RELOCATION......................................................................2

RELOCATION SUMMARY.................................................................................................................3

ELIGIBILITY FOR BENEFITS............................................................................................................4

Dependents Eligible for Benefits..............................................................................................4

RELOCATION REPAYMENT AGREEMENT...................................................................................5

TAX LIABILITY ON RELOCATION EXPENSES PAID TO YOU OR ON YOUR BEHALF........5

MISCE3LLANEOUS EXPENSE ALLOWANCE...............................................................................6

LEASE CANCELLATION...................................................................................................................7

Relocation Clause.....................................................................................................................7

HOME SALE ASSISTANCE PROGRAM...........................................................................................8

You Must Work with Altair......................................................................................................8

Eligibility of the Home..............................................................................................................8

If your home is ineligible for the Home Sale Assistance Program...........................................10

If your home is eligible for the Home Sale Assistance Program..............................................10

Step 1: Speak with your RMC consultant before signing any agreements(s) with real

estate professionals regarding the sale of your home...............................................................11

Step 2: Broker's Market Analysis.............................................................................................11

Step 3: Selecting a broker or agent to sell your home..............................................................11

Step 4: Listing your home for sale............................................................................................12

Step 5: Work closely with the broker and the RMC to locate a buyer for your home.............12

Step 6: Review any purchase offers on the home with your RMC consultant.........................13

Step 7: Amended Value Sale....................................................................................................13

Step 8: Closing an Amended Value Sale..................................................................................14

Step 9: Cost of Ownership........................................................................................................15

Step 10: Vacating the Home.....................................................................................................15

Tax Liability.............................................................................................................................16

Tax Liability.............................................................................................................................16

NEW HOME FINDING ASSISTANCE...............................................................................................16

Home Search Trip.....................................................................................................................16

Business Expenses....................................................................................................................17

Tax Liability.............................................................................................................................17

LENDER REFERRAL..........................................................................................................................18

HOME PURCHASE CLOSING COSTS..............................................................................................18

Closing Procedures...................................................................................................................18

Eligible Closing Expenses........................................................................................................18

Non-eligible Closing Expenses.................................................................................................19

Tax Liability..........................................................................................................................…19

HOUSEHOLD GOODS MOVING.......................................................................................................20

Insurance................................................................................................................................…20

Moving Services........................................................................................................................20

Household Goods Storage.........................................................................................................21

Transportation of Automobiles.................................................................................................21

Disconnecting and Connecting Appliances/Utilities.................................................................21

Employee Relocation Guide – Officer May 1, 2022

PG&E

Table of Contents

Special or Extraordinary Shipping Requirements Are Your Responsibility..........................21

Authorized Household Goods Eligible for Moving Benefit...................................................21

Additional Exclusions.............................................................................................................22

Important Information Concerning Household Goods Shipping............................................23

Tax Liability............................................................................................................................24

TEMPORARY LIVING EXPENSES..................................................................................................25

Trips Home..............................................................................................................................25

Tax Liability............................................................................................................................25

FINAL TRIP.........................................................................................................................................26

Tax Liability............................................................................................................................26

EXPENSE REPORTING.....................................................................................................................26

Employee Relocation Guide – Officer May 1, 2022

PG&E

Table of Contents

Getting Started

Your Relocation Guide

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

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

Important Notices

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

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

Your housing status in the departure location will determine applicable housing benefits (ie. if you are a renter at departure, then the lease cancellation would apply. If you are a homeowner, the home sale benefit would apply).

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

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

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

Time Off for Relocation Needs

The decision to grant time off from work for relocation-related activities is a business decision, and employees are encouraged to discuss needs with their supervisor. The decision to grant time off with pay and the charge of the time off with pay is up to the individual department. Recommendation is not to exceed 5 days over the course of the 12-month relocation.

Employee Relocation Guide – Officer May 1, 2022

Altair Will Administer Your Relocation

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

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

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

Relocation policies and related documents

Online messages about your relocation

Submit and track expense reimbursement requests

Employee Relocation Guide – Officer May 1, 2022

Relocation Summary

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

PROVISION	OFFICER RELOCATION BENEFITS
Tax Liability	Most taxable reimbursements are grossed up to compensate for the tax impact on the employee. Gross-up is provided as a financial benefit, but it is not intended to compensate you completely for all tax liabilities.
Miscellaneous Expense Allowance	$7,000 (less applicable taxes).
Lease Cancellation	Necessary cancellation expenses up to two months’ rent.
Home Sale Assistance	Includes professional home marketing assistance to support efforts to sell your home and implementation of a home sale assistance process that provides significant tax savings for both you and PG&E when an offer is received from an outside buyer. You must call your RMC consultant before contacting a broker to list your home.
New Home Finding Assistance	Maximum of two trips for a combined total of up to 8 days/7 nights for you and your spouse/registered domestic partner; eligible relocating children may go on one trip. Transportation (baggage fees not covered), lodging and meal per diem of $50 per adult and $25 per child under 16 per day. Full day rental tour if seeking permanent rental accommodations.
Lender Referral	The RMC provides counseling and referral to lenders that offer special programs.
Home Purchase Closing Costs	Reimbursement will be equal to actual costs or 2.0% of the new home purchase price, whichever is less. You must call your RMC consultant before contacting a real estate agent to be eligible for closing cost reimbursement.
Household Goods Moving	Packing, loading, transportation, and insurance; 90 days in-transit storage for authorized household goods; up to 2 cars shipped if move is over 400 miles and the car shipment is within the U.S.
Temporary Living Expenses	Up to 6 months of corporate housing; a maximum of 2 round trips or mileage reimbursement for you to return to the departure location OR your spouse/registered domestic partner to visit the destination location. Up to 14 days of rental car while your personal auto is in transit.

Employee Relocation Guide – Officer May 1, 2022

Final Trip

Reasonable expenses for employee and eligible dependents. Meal per diem of $50 per adult and child 16 and older and $25 per child under 16 Lodging reimbursed with original receipts. One-way airfare and baggage fees for up to $100 in total per person if move is over 400 miles; or mileage reimbursed at the current IRS rate. One night’s lodging and meals prior to departure, en route, and one night’s expenses at destination.

Expense Reporting

Employee-paid eligible relocation expenses reimbursed by the RMC upon receiving completed expense form with itemized receipts for all expenses.

Employee Relocation Guide – Officer May 1, 2022

Eligibility for Benefits

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

Your position is Vice President or higher.

Your new commute must be AT LEAST 50 miles FURTHER than your current commute. To determine eligibility:

Mileage from CURRENT home to NEW headquarters:     miles Mileage from CURRENT home to CURRENT headquarters:     miles Difference (must equal 50 miles or more):     miles

The relocation must result in a commute which is substantially reduced, that is by at least 50 percent. Your new residence must be closer to the new headquarters than the former residence. Moves over 100 miles require the new residence to be within 50 miles of the new headquarters. Moves less than 100 miles require that the commute be reduced by at least 50 percent. You must relocate your primary residence within one year from the effective date of transfer. Establishing a permanent residence is defined as the employee and family establishing a permanent tax base in the new headquarter area.

The relocation is between locations within the U.S.

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

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

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

You must not have had a relocation paid for by the Company in the last twenty-four (24) months; and

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

Dependents Eligible for Benefits

Eligible dependents include:

Your legally married spouse, your legally state-recognized common-law spouse, or registered domestic partner

Your children who are under age 26, including step children, children born during a registered domestic partnership, foster children, legally adopted children, and children for whom you have been permanently appointed legal guardianship by a court (does not include the legal wards of your spouse)

The children of your spouse or registered domestic partner who are under age 26, including legally adopted children. Note that a child for whom your spouse or registered domestic partner is the legal guardian is not an eligible dependent.

Documents or certifications may be required to determine eligibility.

Employee Relocation Guide – Officer May 1, 2022

Relocation Repayment Agreement

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

Resignation within the 1st year: 100% Resignation within the 2nd year: 50%

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

No relocation benefits, including payments, will be made until a signed copy of the Relocation Repayment Agreement is on file.

Tax Liability on Relocation Expenses Paid to You or On Your Behalf

Most of the amounts expended by PG&E on your behalf during relocation, whether reimbursed to you or paid directly to the service provider, will be included in your annual income and will appear on your W-2 issued in January of the following year.

PG&E will provide tax assistance for most taxable benefits through a process called “gross-up.” The RMC will calculate the amount of gross-up to which you are entitled and report it to PG&E. PG&E, through the payroll department, will pay additional funds directly to the appropriate tax authority to help offset the tax liability.

Please take note of these important factors pertaining to your gross-up benefits:

The tax assistance provided by PG&E will be calculated using supplemental federal, state and local rates and will include Social Security and Medicare if applicable.

Certain relocation expenses, which are not grossed up, may be deductible on your individual tax return.

Gross-up is provided as a financial benefit, but is not intended to compensate you completely for all tax liabilities.

You are responsible for calculating, reporting and paying all personal federal, state and local income taxes for which you are liable. The RMC will send you a detailed gross-up package that itemizes all relocation expenses for the tax year, including the gross-up payments the Company provides on your behalf. The package is provided for your information and for use by your tax professional if you use such services.

Employee Relocation Guide – Officer May 1, 2022

The services of tax and legal professionals are recommended.

Employee Relocation Guide – Officer May 1, 2022

Miscellaneous Expense Allowance

PG&E’s relocation program does not cover every expense you are likely to incur during your move. To help you with these various costs, PG&E provides a Miscellaneous Expense Allowance (MEA) of $7,000 (less applicable gross earning taxes—no gross-up is provided). The MEA will be paid out by PG&E once you have relocated to your new headquarters area.

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

The MEA will be distributed directly to you by PG&E through Payroll. The RMC will notify PG&E to initiate the payment once your signed Repayment Agreement has been received and you have started work in your new location. If you are a current employee, the position change or other transactions must be completed in SAP prior to payment.

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

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

Alcohol, wine and wine cellar shipment

Tips to movers

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

Concessions negotiated in the sale of a home

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

Personal telephone calls (long distance, cell phone charges)

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

Security or utility deposits

Automobile registration fees, licenses, or smog control charges

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

Child care expenses

Spouse/domestic partner employment costs

Pet deposits or moving and boarding of pets

Laundry and cleaning

Tax obligations not fully compensated by gross-up

GPS and other upgrades not standard for your rental car

Employee Relocation Guide – Officer May 1, 2022

Lease Cancellation

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

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

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

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

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

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

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

If you are renting in one location and have a home to sell in another location, you can only receive one benefit – either lease cancellation to break a current lease, or home sale costs to sell your home. If you take the “renter” benefit and receive reimbursement for lease cancellation, you will not be eligible for the home sale benefit.

Relocation Clause

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

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

Employee Relocation Guide – Officer May 1, 2022

Home Sale Assistance Program

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

You Must Work with Altair

To receive home sale benefits you must contact PG&E’s Relocation Management Company (RMC), Altair, for referral to approved real estate agents in connection with the purchase and/or sale of your residence. You must comply with the Home Sale Program requirements, which includes your agent paying a referral fee to the RMC, or you will not be eligible to receive your commission and closing cost benefits.

If Altair is unable to collect a referral fee from the listing agent, you will not receive the home sale closing cost benefit.

Eligibility of the Home

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

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

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

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

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

The residence is in good and marketable condition.

The residence is not presently under renovation.

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

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

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

Employee Relocation Guide – Officer May 1, 2022

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

Condominiums must meet the following guidelines:

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

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

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

The units in the complex are mortgageable by FNMA standards.

The Condominium Association is in sound financial condition as evidenced by (I) current financial statements, (II) sufficient replacement reserves, (III) no rapid increase association dues and (IV) no unusual or excessive liens.

You are responsible for providing verification of the above.

Some properties may not qualify for the Home Sale Assistance Program. The following list is not all inclusive, but provides some common examples:

Homes with leased solar panels

Unusual homes such as geodesic domes, earth homes, log cabins, houseboats, A-frames, and other specialty homes

Rural residential zoning or lots larger than one acre

Cooperative apartments

Mobile homes and/or trailers

Residences that require an association’s approval of purchaser

Secondary tracts of land

Farm properties

Homes with structural problems to the extent they are deemed, by a qualified structural engineer, to be unsalable

Homes that are ineligible for standard financing

Any home built with synthetic stucco; LP, composite, or masonite siding (unless remediated); or containing any other materials which are involved in, or could be potentially involved in, a class action lawsuit

Homes with toxic mold or excessive levels of hazardous substances

Vacation homes

Investment properties

Apartment buildings

Other factors which may affect the eligibility of a property for this program include, but are not limited to, the following:

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Legal/title problems (liens, judgments)

Property line issues (properties with private roads must have a recorded road maintenance agreement)

Structural problems/damage

Expansive soil

Safety or code violations

Unmarketable title

Inability to meet conventional lender or insurance requirements

Properties in foreclosure

Bankruptcy

Special financing (e.g., first-time buyers)

If your home is subject to any of the items listed above, inform your RMC consultant.

When you request the RMC’s assistance, your home must be available for sale. It cannot have been rented or leased within the past 12 months. It cannot be rented or leased after you elect to participate in the Home Sale Assistance Program. All construction and/or repairs must be completed prior to requesting to participate in the Program.

PG&E RETAINS THE RIGHT TO MAKE THE FINAL DECISION ON THE ELIGIBILITY OF A HOME FOR THE HOME SALE ASSISTANCE PROGRAM.

If your home is ineligible for the Home Sale Assistance Program

In accordance with the criteria identified above, or by the judgment of the RMC and PG&E, you will be responsible for selling your home on your own. You will still receive direct reimbursement for reasonable and customary home sales expenses. For reference, a list of reasonable and customary home sale expenses covered by PG&E can be found on page 13. Your home sales expense reimbursement will be grossed up.

If your home is eligible for the Home Sale Assistance Program

In accordance with the criteria listed above and you choose not to participate in the Home Sale Assistance Program, you will still receive reimbursement for reasonable and customary home sale expenses; however, none of the expenses of the transaction will be grossed up.

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Step-by-Step Guide to Home Sale Assistance Program

You must follow these steps carefully to ensure compliance with the Home Sale Assistance Program. If these steps are altered in any way, your home sale assistance benefits may be at risk.

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

As soon as PG&E authorizes the RMC to provide services, your consultant will contact you to conduct an initial interview. This interview will include discussion of all aspects of your relocation benefits and the needs that you anticipate for your family during the relocation process.

Step 2:    Broker’s Market Analysis

After the initial interview, your consultant will order two Broker’s Market Analyses of your home and review them with you. A Broker’s Market Analysis (BMA) is performed by a real estate broker on the basis of his or her knowledge of the current real estate resale activity in the community. Each Analysis will compare your home with other similar, recently sold homes to attempt to answer the question:

“What will the home sell for in the next three to four months, as is, with usual financing for

the area?”

The average value of the BMAs will be the basis for the initial listing price for your home under the Home Sale Assistance Program. The home should be listed for no more than 5% over the average of the two BMAs’ most probable sales price. (Following the appraisal process, you will need to adjust your list price so that it is not more than 5% over the value provided in your Guaranteed

Purchase Offer.) Adherence to the Home Sale Assistance Program requirements, including list price caps, is necessary to receive the home sale assistance and home purchase benefits outlined in this guide.

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

You may want to list your home with one of the brokers who provided a BMA, but you are not required to do so. Talk over your broker preferences with your RMC consultant. If you wish to consider additional brokers, the RMC will provide referrals. You are free to choose a broker or agent you already know, subject to RMC approval. Approval must be granted before you take any action regarding the price, terms and service requirements of the listing. In addition, your agent may not be your relative (defined as a parent, child, spouse, domestic partner, sibling, in-law, stepparent, stepchild, grandparent, or grandchild) as it is a conflict of interest for the Company to reimburse members of a relocating family for services (commission) connected with the sale of the old home or purchase of a new home.

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Step 4:    Listing your home for sale

After you have chosen a broker or agent, you will be asked to sign a listing agreement. The following

“Exclusion Clause” must be included as a signed addendum to your listing agreement:

“It is understood and agreed that regardless of whether or not an offer is presented by a ready, willing and able buyer:

(1)    That no commission or compensation is earned by, or is due and payable to, broker until sale of the property has been consummated between seller and buyer, the deed delivered to the buyer and the purchase price delivered to the seller; and

(2)    That the seller reserves the right to sell the property to Altair Global or any other person(s) designated by Altair (individually and collectively a “Named Prospective Purchaser”) at any time upon which this listing agreement shall terminate without obligation by Altair or the parties to this agreement and no commission or

compensation will be due.”

The exclusion clause must be attached to the listing agreement as a signed addendum. This clause will prevent PG&E from paying the listing broker double commission when the home is sold.

The commission may not exceed 6% without prior approval from PG&E. The term of any listing agreement should not exceed 90 days. Your RMC consultant may recommend a shorter term under certain circumstances.

Establish a realistic list price for the home. Your RMC consultant will offer advice on the best listing and selling prices, based on current market data provided by real estate professionals in the community. You are encouraged to participate in this process by providing relevant data to the brokers chosen to assess value. The advantages of a competitive listing price will be explained fully by your consultant.

You must complete a home sale disclosure statement. Every home seller has certain legal duties and obligations to a buyer, including full disclosure of all pertinent information about the condition of the home and its surroundings. If the RMC inadvertently or without proper disclosure information purchases a home ineligible for the Home Sale Assistance program, and PG&E incurs a loss as a result of your omission or misrepresentation of information, you must repay PG&E any current and future out-of-pocket expenses, and/or fines or legal judgments paid or to be paid by PG&E with regard to the property.

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

Your RMC consultant will work directly with the real estate broker or agent to monitor progress in marketing your home. The consultant will make constructive suggestions and note any market activity

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that might impact the sales strategy. You will be contacted regularly by the consultant to discuss current information and revise the sales strategy as

needed. You are encouraged to carefully evaluate these recommendations, but you are not required to accept them.

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

Signing any purchase offer or accepting any earnest money deposits from a buyer or broker prior to speaking with your RMC consultant will place your Home Sale Assistance benefits at risk.

You should contact your RMC consultant immediately when you receive any offer to purchase your home. Your consultant is available by phone toll-free during office hours or after hours by calling the number listed on his or her business card, and he or she will tell you what to do if the offer is acceptable to you.

If an offer from a buyer is acceptable, the RMC will sign the contracts. The RMC’s obligation to you and PG&E is to determine if the buyer is qualified and if the offer is bona fide before approving the contract.

It is important to proceed with care in evaluating a purchase offer because some costs may not be reimbursable. If the buyer’s purchase offer requires the seller to pay any concessions or buyer’s expenses at closing those costs will be deducted from your equity. The following list provides guidelines for consideration as you negotiate a purchase offer; however, you should consult your RMC consultant if there is any question about whether a cost will be paid under PG&E’s relocation benefit program.

PG&E Will Pay (if normally required of seller)

PG&E Will Not Pay

Document preparation fees Survey fees Mortgage release fees Recording fees Transfer taxes Title insurance Closing and legal fees Escrow fees FHA/VA fees (required by seller) Attorney fees, if an attorney is required to handle the actual closing Termite or pest inspection Radon inspection or warranty, if necessary Normal and reasonable real estate broker’s commission (not to exceed 6% of purchase price, unless approved in advance by PG&E)

Discount points (FHA, VA or conventional) Escrow Insurance Utility bills Property taxes Rent Seller concessions included in the contract with the buyer, including buyer’s closing costs, home warranties, repairs, remodeling, restoration or renovation of any kind Expenses to remedy and bring to acceptable standards hazardous conditions in the home, such as: Radon gas Friable asbestos Lead-based paint Urea formaldehyde foam insulation Underground storage tanks containing toxic materials Similar environmental hazards Pest control

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Step 7:    Amended Value Sale

Amended Value Sale is a procedure that will be used when you find a buyer for your home. The Amended Value Sale Program consists of two separate, arm’s length transactions:

The RMC purchases the home from you at the same net price and terms as the bona fide offer that you have received from a buyer. Once the sale to the RMC closes and you vacate the home, subject to disclosure obligations, you are no longer financially or legally responsible for the home.

The RMC, as the owner of the property, sells the home at the previously offered price to the buyer who made the offer. If something should happen to prevent this second sale from taking place, you are not affected.

Because the RMC, on behalf of PG&E, is buying your home based on the value of the offer you have received, the RMC must be sure that the offer is bona fide and that the buyer is ready, willing and able to purchase your home. Your consultant will work closely with you and your broker as you consider any offers to be sure that the terms are acceptable to the RMC and PG&E.

In order for an offer to be eligible for the Amended Value Sale Program, it must meet certain requirements, including:

The contract of sale from the buyer must specify a closing date that is within 60 days of the contract date.

The contract must not be contingent on the sale of the purchaser’s home. It can, however, be

contingent on a closing scheduled to occur within thirty (30) days of the contract date.

The contract must not contain other contingencies, with the exception of inspections and

buyer’s approval for financing.

If the RMC cannot accept the contract of sale because the buyer is not qualified with a bona fide offer, you must continue to market the home. If you choose to accept the contract of sale with the buyer against the recommendation of the RMC, you will be responsible for managing the process as an independent sale, outside of the Home Sale Assistance Program. In this case, you will still receive direct reimbursement for reasonable and customary home sale expenses; however, none of the expenses of the transaction will be grossed up.

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Step 8:    Closing an Amended Value Sale

When an acceptable offer to purchase the home has been received, documents previously sent by the RMC will require immediate attention. The documents will include a contract of sale between you and the RMC, certain financial information forms and a general warranty deed that will subsequently be used by the RMC to convey title. Your consultant will offer specific advice as required, but you (and your spouse, if applicable) should plan to execute the documents as soon as possible before a Notary Public and return them to your RMC consultant. It will not be necessary for you to attend the closing of the sale.

You will receive your equity directly from the RMC when the Contract of Sale documents are signed or the property is vacated, whichever is later. Payment will be by either check or electronic transfer. You will also receive a detailed equity statement by email, mail, or fax explaining every adjustment to the equity. In general, the equity will be calculated as follows:

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To determine the total “net” cash value of any transaction on the home under the Home Sale Assistance Program, first add together:	1.    The purchase price appearing in the RMC’s contract of sale, wherein you are the seller and the RMC is the purchaser. 2.    Any amounts you have prepaid for which you are entitled to receive a prorated refund, such as interest and taxes, but excluding home casualty insurance.
Then subtract from the above the total of the following amounts (if any) that are applicable:	1.    All outstanding indebtedness (mortgages, tax liens, judgments, etc.) 2.    Charges for prorated items such as interest and taxes through the effective date of the contract of sale between you and the RMC or through the vacate date, whichever is later. 3.    Concessions to which you agreed as the seller. 4.    Costs for deferred maintenance/repairs to be completed before the home can be purchased. 5.    A vacate holdback of $500, refundable to you after you have permanently vacated the property and the RMC has verified property condition.
The difference is:	The net equity under the Company relocation program.

Step 9: Cost of Ownership

The sale price in the Contract of Sale between you and the RMC will reflect the cost of ownership of the home (property insurance, taxes, utilities, maintenance and interest on the mortgage) through the effective date of the contract of sale between you and the RMC or the vacate date, whichever is later. The equity statement from the RMC will provide a detailed accounting of your home sale transaction.

It is acceptable to cancel your property insurance as of your vacate or acceptance date, whichever is later. However, for liability purposes it is recommended that your property insurance remain in effect until your new policy is in force. It is your responsibility to contact your insurance carrier to advise them of cancellation.

Your RMC consultant will advise you when to discontinue making mortgage and other payments. If you have arrangements with any lender for payments to be automatically deducted from your account, it will be your responsibility to cancel the automatic draft(s) as of your acceptance or vacate date whichever is later. It is imperative you discuss with your RMC consultant when to send this form to your lender. If you fail to cancel your automatic draft(s), refunds for overpayments will be delayed until after closing.

Step 10:    Vacating the Home

If you vacate prior to closing, your real estate broker will make arrangements to pick up your house keys, warranties, garage door opener controls and other such necessities. Your consultant will notify you when to transfer utilities to the broker’s name, but do not request the utilities be turned off as this will result in reconnect charges. Please be sure to contact the utility companies to provide your forwarding address for your final bills.

Regardless of whether you vacate before or after closing, it will be necessary to leave the home in cleanly swept condition. In order to avoid paying additional cleaning charges later, the home must be

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clean and you must remove all personal property, trash or debris. Cleaning charges will be withheld from the refund of your “vacate holdback” (Step 8, item 5 in the Guide for Calculation of Equity) if necessary.

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Tax Liability

The majority of expenditures associated with this benefit are not reported as gross earnings; thus no gross-up is necessary provided the home sells under the Amended Value Sale program. The only exception to this is the expenditures associated with the deed and transfer tax of the property in some states.

Tax Liability

This benefit is not reported as gross earnings, and no gross-up is necessary.

New Home Finding Assistance

Do not contact any real estate professional at the destination without the guidance of your RMC consultant. When you are ready to visit your destination to look for suitable housing, the RMC must arrange your travel and lodging and take care of many of the details for you.

PG&E will provide you with assistance in searching for your new residence. Specifically:

Before you depart to look for housing in the new location, your RMC consultant will ask you for detailed information concerning your housing preferences, price range and family requirements.

If you wish to rent, the RMC will arrange for a rental service or a real estate broker to assist you in locating the right place for you.

If you choose to purchase a home, a real estate broker will arrange for house-hunting tours for every day you are in the area. You will be escorted to neighborhoods and homes of interest to you. Through your broker or agent, you will see homes targeted to meet your goals and needs.

Rental Assistance

In order to assist employees intending to rent or lease a home or apartment in the new location, one

(1) full day tour with a rental finding company/brokerage will be provided. Your RMC consultant can assign you to a qualified local company in your destination area to provide you with the following information:

General availability of apartments, houses, and condominiums for rent and the range of rental rates

Local real estate practices governing such matters as who prepares the lease, the amount of commission if any, and the security deposit required

Application fees and/or security deposits for rentals are not a reimbursable expense.

Home Search Trip

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You and your spouse/registered domestic partner may take up to two home search trips for a maximum of eight days, seven nights total. Dependent children who will be relocating to the destination with the family will also be eligible for one home finding trip.

The following conditions apply to travel expense reimbursement:

All travel arrangements must be made through the RMC.

Itemized receipts are required for reimbursement. Submit the Expense Report through the RMC’s website.

Airline reservations should be made a minimum of seven days in advance. If you wish to drive, you will be reimbursed mileage at the current IRS rate for business travel.

Travel booked during a public holiday period needs to be reviewed by the consultant.

Baggage fees are not reimbursable for this trip. You may use your Miscellaneous Allowance to cover baggage fees.

Expenses for transportation to and from the airport, parking, and tolls will be reimbursed in accordance with the Company business travel policy.

Reasonable lodging will be provided for employee and spouse/domestic partner together for the trip.

Expenses for car rental and gas will be reimbursed. Expenses for a GPS or upgrades not standard for the rental car will not be reimbursed.

Meal per diem of $50 per adult and child 16 and over per day. Children under 16 receive $25 per child per day. Receipts are not required for reimbursement.

If you cancel a travel booking and there is a cancellation fee, you will be required to pay any ticket change fees and /or fare increase using your MEA.

Do not use your corporate credit cards for relocation expenses. In addition, do not use your company car for activities related to relocation, as the IRS considers such use as taxable income to you.

Cancellations for rental tours require a 48-hour notice. Charges will apply if the 48 notice is not provided. Continued cancellations may result in loss of benefit or future tours conducted at an out of pocket expense.

Business Expenses

Should you incur business expenses during the home finding trip, these expenses must be segregated from relocation expenses and submitted to PG&E separately to avoid relocation tax liability.

Tax Liability

New Home Finding benefits are reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

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Lender Referral

One of the critical aspects of buying a new home is obtaining mortgage financing. The RMC will provide you with a list of representatives of selected local and national mortgage companies that will offer loan programs for your use. You are not required to use any of the lenders referred by the RMC, but they typically offer mortgages at competitive interest rates and reduced fees. Your designated mortgage company will provide details on financing your transaction.

Home Purchase Closing Costs

You are eligible for reimbursement of normal closing costs when you purchase a home at the new location. To receive this benefit, you must close the purchase of your new home within one year of your report date at the destination location. To receive home purchase benefits, you must contact PG&E’s Relocation Management Company (RMC), Altair, for referral to approved real estate agents in connection with the purchase of your residence. You must comply with the Home Purchase requirements, which includes your agent paying a referral fee to the RMC, or you will not be eligible to receive your closing cost benefits.

You must move into your new residence within 10 days of closing on it. No additional storage or temporary housing will be extended to accommodate a new home remodel.

Closing Procedures

Your mortgage company will provide details on financing your transaction.

Your consultant will review your closing documents to make certain that the charges are in order, consistent with your negotiated purchase contract and within the limits of reimbursements that will be paid by PG&E.

All eligible costs will be paid by the RMC at closing so that all you need to provide when you close the purchase of your home is the down payment and any concessions or other non-eligible costs.

Eligible Closing Expenses

Closing costs reimbursement will be equal to actual costs or 2.0% of the new home purchase price, whichever is less.

Appraisal fee, if required by lending institution

Credit report

Settlement or closing fee

Title insurance

Document preparation

Notary fee

Attorney’s fees

Government recording and transfer charges (only if required of the lender)

Survey (only if required of the lender)

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General home inspection

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Pest or termite inspection (only if required of the buyer)

Application fee, commitment fee, processing fee, etc.

Note: The items listed above are not all inclusive. Eligible expenses may vary by local custom. Your RMC consultant will advise you regarding expenses covered by PG&E.

Non-eligible Closing Expenses

Specifically excluded from reimbursement are prepaid expenses such as:

Prorated interest

Discount points

Origination fees expressed as a percentage of the loan amount

Taxes

Homeowner’s insurance

Mortgage insurance

Earnest money payments

Property mortgage insurance for insufficient down money

Tax or insurance escrow

Home warranties

Any fees associated with second mortgages

Tax Liability

The Closing Cost Benefit is reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

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Household Goods Moving

Your belongings will be shipped by one of the RMC’s select moving companies.

Your consultant will arrange for the van line’s household goods move coordinator to contact you and provide you with details surrounding the movement of your household goods. The moving company will need sufficient time to properly coordinate your move. A minimum notice of 30 working days is required. During holidays and summer months, more lead-time is required. Packing and loading dates will be arranged with every attempt made to provide these services on the dates you request. However, keep in mind that PG&E will not authorize or reimburse additional costs of weekend or holiday service. If you request a weekend or holiday move, the overtime charges will be collected directly from you upon delivery. You are required to inventory items being moved and check them off when you arrive in the destination. You or a designated representative should be present during packing, unpacking and loading, unloading. Additional details provided in the section on Important Information Concerning Household Goods Shipments. Local moves (under 50 miles) will not be accommodated.

Important – Do not give notice to a landlord to vacate your apartment prior to confirming with the van line that you have a firm move date.

Insurance

Replacement cost insurance up to $100,000 is provided at no cost to you. If you require additional coverage in excess of that provided, the cost will be billed to you by the RMC.

Moving Services

The selected household goods carrier will pack, load, insure, transport, deliver and unpack your normal household goods. There are some limits to this service. Furniture and boxes will be placed in your home where specified, and the contents of your boxes will be unpacked and placed on the closest flat surface, if requested. Unpacking beyond this description is considered a settling-in service or maid service and may be obtained from the moving company at an additional cost to you.

Depending on the complexity of services you require, some additional services may be performed by your moving company or a third-party service firm when deemed necessary by the RMC and within reasonable costs. Such “third-party” services, including crating, will be considered for normal household goods only and will not include service for items affixed to the property.

It is strongly recommended that you take advantage of the packing services provided by this guide. If you pack yourself, no cost saving is realized and none of the goods that you pack will be insured.

If you are unavailable for a pick-up or delivery and do not notify movers in advance, any additional charge will be billed to you.

Some examples of items typically covered for crating are: marble/glass top tables, mirrors and glass shelves.

Items not covered: artwork, taxidermy, more than 4 TV’s, aquariums, yard art, fountains and chandeliers.

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These lists are not all inclusive. If you have any items that are not covered for crating, you may use your Miscellaneous Allowance to pay the 3rd party company directly

Household Goods Storage

Storage of household goods and personal effects in transit will be covered up to 90 days, but only if storage is unavoidable. If storage is required for more than 90 days or if you need to access any stored items, the charge will be billed to you.

Storage will not be extended to accommodate a new home remodel.

You will be responsible for costs beyond the time period allowed by this guide.

Transportation of Automobiles

PG&E will pay for shipping up to two personal automobiles within the U.S. if the move is greater than 400 miles. The vehicles must be in working order and must fit on a standard car carrier or moving van. The value of the vehicles to be moved must exceed the cost of shipment.

If you wish to have your car transported in a covered car carrier, you can pay for the cost using your MEA.If the move is less than 400 miles, you are required to drive the cars you own to the new location or ship them at your own expense. Mileage and tolls via the most commonly used direct route will be reimbursed at the current IRS rate.

Disconnecting and Connecting Appliances/Utilities

PG&E will cover the cost of disconnecting and connecting normal household appliances or any other article requiring special servicing for safe transportation. Appliances include washer, dryer, refrigerator, stand-alone freezer and icemaker. However, the extension of any gas or electric lines or adding service for mismatched appliances (i.e., converting an electric hook-up for a gas appliance) is excluded.

Special or Extraordinary Shipping Requirements Are Your Responsibility

Plans should be made in advance for items requiring special or extraordinary handling. These shipping arrangements and the costs will be your responsibility, but call your household goods move coordinator or your relocation consultant for advice.

PG&E will not pay for charges by the moving company to pick up any furnishings or material at any site other than your primary residence. You will be billed directly for this additional service.

Authorized Household Goods Eligible for Moving Benefit

Clothing and personal items

Furniture and fixtures (not attached to the house)

Major appliances

Gardening equipment

Pianos (3rd party service to lock/unlock keys and re-tuning not covered)

Grandfather clocks

Pool tables (3rd party service to disassemble and reassemble are not covered)

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Waterbeds (if drained and disassembled)

Items NOT Authorized:

The following is a list of items for which PG&E will not authorize transportation.

Boats, trailers, airplanes, motorcycles 250 cc and over, snowmobiles, off-road vehicles, travel trailers, pop-up trailers, camper inserts for pick-up trucks, or other recreational vehicles

Livestock or domestic animals

Taxidermy

Frozen/perishable foods

Alcohol, wine and wine cellar shipment

Liquids in unsafe containers/flammable liquids, items that may contaminate or damage other goods

Valuable papers/securities/money

Valuable jewelry/precious stones/firs/items of extraordinary value

Heavy machinery/tractors/farm equipment larger than normally required for yard and garden maintenance

Lumber or other building materials

Plants

Antiques and fine art

Animal-drawn carriages or wagons, vintage and show automobiles

Storage sheds, greenhouses, play houses or other outside buildings

Campers, motor homes, livestock trailers

Satellite dishes greater than 24” in diameter/ solar panels

Coins, stamps and other fine collectibles

Items associated with an in-home business

Hot tubs/spas/above-ground pools

Ammunition and/or explosives

Firewood/coal

Items from a temporary residence

Items that cannot be attached a value (personal paints, pottery, etc.)

Auto parts

Any other items which cannot be packed or moved by a standard commercial carrier

Any goods/materials prohibited by law

Note: Gas grills may be shipped but must be emptied and certified before loading.

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Additional Exclusions

Maid service or housecleaning service

Tips to movers

Disassembly/assembly of swimming pools, swing sets, basketball goals, gym equipment (including treadmills, Pelotons, etc.), chandeliers, TV/radio antennas or similar personal property. If such items are disassembled prior to packing, they may be transported.

If movers assemble or disassemble unusual items, you will be billed directly.

Insurance for items of extraordinary value such as antiques, fine art, coin and stamp collections, precious metals, documents, securities and notes, or insurance above the coverage provided by PG&E.

Draining and refilling of waterbeds.

Establishing services such as power, water, gas, telephones, etc.

Exclusive use of moving van or space reservation

Unauthorized extra pick-ups or deliveries, such as from a storage unit

Unauthorized overtime packing and unpacking

Unauthorized crating

3rd party services such as hoisting of furniture, moving safes or heavy equipment.

Crating of TV’s is limited to 4 TV’s. Dismounting and remounting of TV’s is not covered.

Storage of automobiles

Important Information Concerning Household Goods Shipping

Valuables such as jewelry, coin and stamp collections, computer programs, currency, precious metals, gems or semi-precious stones, rare documents, or most other collectibles should be set aside and transported with you when you travel. Only under certain very specific conditions is the mover responsible for these items. Be certain to ask the representative of your moving company about transporting valuables when he or she visits your home to inventory your belongings.

Firearms may be transported, but must be unloaded, packed separately and inventoried by type of firearm and serial number. The inventory must be included in the documentation of the move. This is for your protection as well as the protection of the mover. You will be responsible for meeting the licensing or registration requirements, if any, of the state where you are moving. You cannot ship live ammunition via household goods movers.

Accompany the mover through the home as he or she inventories and tags each item to be moved. Plan to check off the items at the destination as well; otherwise, you may have difficulty with claims settlements should they prove necessary.

You or your representative should be present during packing and loading. Do not release the drivers until a complete inspection of the home and property has been accomplished, since items left behind could result in extra charges to you.

Detach items that are to be moved, such as televisions, wall-mounted can openers and coffee makers, pictures, posters, curtain rods, attached bookcases and the like. Unplug appliances and electrical devices such as stereos and computers; if possible, stow the connecting cords and cables.

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Remove all items from refrigerators. Unplug, defrost, clean and let stand open to dry at least 24 hours in advance of loading.

Items that cannot be moved by your household goods mover:

Bleach

Propane tanks or butane tanks

Flammable or combustible items of any kind, including gas and oil in lawn mowers, edgers and other yard or utility equipment

Open liquids of any kind

Frozen foods

Aerosol cans or paints

No mover will accept liability for moving plants. If you choose to allow the mover to move your plants, you do so at your own risk.

Note: Federal regulations require that plants moved interstate be inspected and certified free of pests and diseases. The states of California, Arizona and Florida are especially diligent in enforcing their agriculture laws. Taking plants into these states may require considerable extra expense and effort.

If you have items in temporary storage, please give the shipper maximum possible advance notice of the date you prefer delivery. Fourteen days is recommended to ensure the availability of your preferred dates.

Keep your utilities on at the old location until at least the day after the scheduled completion of packing and loading.

In the event damage occurs during the shipment of your goods, please advise your relocation consultant immediately. Auto claims must be filed within 24 hours of the auto’s delivery. The household goods claim must be filed immediately if the goods are going into a self-storage unit and within 90 days of delivery if goods are delivered directly to the home or have been in van line storage.

Tax Liability

Household goods moving and storage expenses are reported as additional gross earnings and the amount will be grossed up to help offset additional taxes.

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Temporary Living Expenses

If you assume duties at the new location before your new home is available for occupancy, the RMC will arrange for temporary accommodations in corporate housing for up to six months as long as you are still financially responsible for your former residence. Temporary living must be arranged through the RMC.

Only lodging expenses will be covered, this includes one parking space at the temporary housing unit. Temp housing may start only 1 week prior to your effective start date.

Rent reimbursement in lieu of temp housing is not covered.

If temporary housing that allows pets is available, you are responsible for pet deposits, related fees, etc.

You are eligible for a rental car for up to 14 days in total while your personal auto(s) is in transit. Should you and your spouse both ship a car and need a rental car while waiting for delivery, please plan your car rental time accordingly. The rental car can be arranged through Altair’s Travel Department and direct billed to Altair. Please fill up the rental car gas tank before returning it to the rental facility. You should use your MEA for this cost, as gas is not a reimbursable expense.

Temporary housing will not be extended to accommodate a new home remodel.

Trips Home

The Trip Home benefit is intended to provide you (the employee) with one trip back to your former residence so that you can meet with movers and assist your family with the final move.

You will be eligible for a maximum of two round trips for you, the employee, to return to the departure location OR your spouse/registered domestic partner to visit the destination location. Only round trip airfare or mileage (the most direct route driving at least 400 miles per day) is eligible for reimbursement for your Trip Home benefit. Items that will not be reimbursed include; transportation to and from the airport, parking, meals and baggage fees. The Miscellaneous Expense Allowance is intended to cover these costs.

Tax Liability

This benefit is reported as additional gross earnings and the amount is grossed up to help offset additional taxes.

Final Trip

Reimbursement will be provided for reasonable in-transit expenses incurred by you, your spouse/registered domestic partner, and eligible dependents while traveling on the final trip from the old to the new location.

Eligible expenses include reasonable travel, such as a shuttle or taxi to the airport, lodging and meal expenses. Meal per diem of $50 per adult/child 16 and over per day. Children under age 16 will receive a meal per diem of $25 per child per day. No receipts are needed for reimbursement. You

Employee Relocation Guide – Officer May 1, 2022

must work with your RMC consultant to make your travel arrangements. Air transportation (coach class with advance purchase) will be provided if the distance is over 400 miles; otherwise, you are required to drive to the new location. Baggage fees for up to two pieces of regular luggage per person will be eligible for reimbursement. You may be reimbursed for up to $100 in total per person for baggage fees. Any additional baggage fees should be paid for using your Miscellaneous Allowance.

If you drive, you will be reimbursed mileage for up to two automobiles. Mileage reimbursement will be based on the current IRS rate for business travel by the most direct route. Other expenses for hotel and meal reimbursement will be based on travel of at least 400 miles per day. No reimbursement is provided for the additional cost of side trips or sightseeing. Mileage will be paid on your own car(s) only. Should you choose to rent a car to drive for your final move, you would be expected to use your MEA for the cost. Expenses are reimbursable for one night prior to departure, en route, and if you are unable to move directly into your new home upon arrival, one night at the destination.

Do not use your corporate credit cards for relocation expenses. In addition, do not use your company car for activities related to relocation as the IRS considers such use as taxable income to you.

You must report actual travel expenses on a Relocation Expense Form and submit to the RMC for approval.

Tax Liability

Final trip expenses are reported as additional gross earnings and are grossed up.

Expense Reporting

Employee Relocation Guide – Officer May 1, 2022

In some circumstances, you are required to pay certain relocation expenses and request reimbursement afterward. Such reimbursement requests must be kept separate from other business expenses and submitted to the RMC, using the Relocation Expense Form.

After submitting the expense report online, the required receipt copies should be submitted to the RMC for approval and processing no later than 30 days after you incur the expenses. To be IRS compliant, expenses must be submitted in the year the expense is incurred. Failure to submit expenses within this time frame could jeopardize reimbursement, your tax assistance, or both.

Reimbursement will be for actual, reasonable costs only, within the guidelines.

Please remember:

You must include copies of itemized receipts for all expenses (except meals) in order to be eligible for reimbursement.

You must include a copy of the expense report when you provide your receipts.

It is wise to make copies of all reimbursement forms and receipts that you submit for your personal records as well as for income tax purposes.

All expense associated with your relocation must be reimbursed within your 12 month relocation benefit period.

Regular business/travel expenses must be submitted separately to PG&E on separate expense reports.

Do not use your corporate credit cards for relocation expenses. In addition, you may not use your company car for activities related to relocation, as the IRS considers such use as taxable income to you.

In addition to other policy provisions regarding the timing of expense reimbursements, any reimbursements of taxable expenses provided pursuant to this program shall be reimbursed on or before the last day of the calendar year following the year in which the expense was incurred, consistent with requirements in Internal Revenue Code Section 409A, as it may be amended.

The amount of expenses eligible for reimbursement is not subject to a multi-year cap. As a result, expenses eligible for reimbursement during one year, do not affect the expenses eligible for reimbursement in any other taxable year.

Employee Relocation Guide – Officer May 1, 2022

EX-10.49

EXHIBIT 10.49

PG&E CORPORATION

2010 EXECUTIVE STOCK OWNERSHIP GUIDELINES

(As adopted effective January 1, 2011, and amended effective December 11, 2024)

1.    Description. The 2010 Executive Stock Ownership Guidelines (“Guidelines”) was approved by the Compensation Committee of the PG&E Corporation Board of Directors effective January 1, 2011. The Guidelines were further amended by the PG&E Corporation People and Compensation Committee (the successor to the Compensation Committee) effective January 1, 2022 to expand participation, revise holding thresholds, expand eligible holdings, and adjust ownership targets. The Guidelines were further amended by the PG&E Corporation People and Compensation Committee effective December 11, 2024 to delegate administration of the hardship exception. The Guidelines are an important element of the Committee’s compensation policy of aligning executive interests with those of the Corporation’s shareholders. The Guidelines are administered by the PG&E Corporation Senior Human Resources Officer.

2.    Ownership Targets. The applicable total stock ownership targets (“Target”) are:

Positions	Total Stock Ownership Target
Chairman, CEO and President, PG&E Corporation	6x base salary
EVPs, PG&E Corporation and Pacific Gas and Electric Company (Utility)	3x base salary
SVPs of PG&E Corporation and Utility	2x base salary
VPs of PG&E Corporation and Utility	1x base salary

    Conformance with the applicable Targets will be determined as of June 30 of each calendar year (“Measurement Date”), taking into consideration legal and similar obligations, commitments, and restrictions in existence prior to the first Measurement Date following amendment of any Targets. Targets will be based on base salary in effect on the Measurement Date.

3.    Retention Ratio. Under the Guidelines, Officers are expected to hold 100 percent of their net shares realized from options exercises or stock or stock unit vesting, after withholding for the exercise price and taxes, until the applicable Target is met.

4.    Timing Requirement. Each officer will have five years in which to meet any newly effective/applicable ownership targets or holding requirements.

5.    Calculation of Stock Ownership Levels. The value of the stock or stock equivalents owned by the Eligible Executive, as of the Measurement Date, is based on the average closing price of PG&E Corporation common stock as traded on the New

York Stock Exchange for the last thirty (30) trading days prior to the Measurement Date (“Measurement Value”).

a)    The value of stock beneficially owned by the Eligible Executive is determined by multiplying the number of shares owned beneficially on the Measurement Date times the Measurement Value.

b)    The value of PG&E Corporation phantom stock units credited to the Eligible Executive's account in the PG&E Corporation Supplemental Retirement Savings Plan (“SRSP”) is determined by multiplying the number of phantom stock units in the Eligible Executive's SRSP account on the Measurement Date times the Measurement Value.

c)    The value of stock held in the PG&E Corporation stock fund of any defined contribution plan maintained by PG&E Corporation or any of its subsidiaries is determined by multiplying the number of shares in such fund on the Measurement Date times the Measurement Value.

d)    The value of unvested restricted stock and/or restricted stock units held by an Eligible Executive on the Measurement Date is determined by multiplying the number of shares underlying such awards times the Measurement Value.

6.    Administration. These Guidelines are administered at the discretion of the People and Compensation Committee. The Committee may determine, based on its judgment and on a case-by-case basis, whether to temporarily suspend such guidelines if compliance would create severe hardship or prevent an executive from complying with a court order. Additionally, in the case of executives with a guideline of 1x base salary and who are not Section 16 officers, the Committee delegates to the PG&E Corporation CEO the authority to determine whether to temporarily suspend such guidelines if compliance would create severe hardship or prevent an executive from complying with a court order. The PG&E Corporation CEO will provide reports to the Committee on any such applications of this delegated authority.

2

EX-19

EXHIBIT 19

Insider Trading Standard

    SUMMARY

It is PG&E’s policy to comply with the letter and spirit of all laws, rules, and regulations related to insider trading.

    TARGET AUDIENCE

All current and former PG&E Board members, officers, employees, and each of their Related Persons (as defined below).

TABLE OF CONTENTS

SUBSECTION    TITLE    PAGE

1Insider Trading Prohibition    1

2Scope of the Insider Trading Standard    2

3Trading Blackout    3

4Transactions Pursuant to SEC Rule 10b5-1 Trading Plans and Mandatory 10b5-1 Plan Requirement for Sales    4

5Pre-Clearance Requirements    4

6Material Nonpublic Information    4

7Additional Restrictions    5

8Post-Termination Transactions    6

9Noncompliance with Insider Trading Laws and the Insider Trading Standard    6

Appendix A, Guidelines For Rule 10b5-1 Plans    9

Appendix B Pre-Clearance Procedures    10

    REQUIREMENTS

1    Insider Trading Prohibition

1.1    Federal and state securities laws prohibit the purchase or sale of a company’s securities by persons who owe a duty of confidence to the company and are aware of material information about the company that is not generally known or available to the public.

1

1.2    These laws also prohibit persons who are aware of such material nonpublic information from disclosing this information to others who may trade in the company’s securities (i.e., “tipping”), even though the “tipper” did not trade and did not gain any economic benefit from the other person’s trading. In addition, persons who receive such material nonpublic information (i.e., “tippees”) may incur liability for illegal insider trading.

1.3    Companies and their controlling persons (as defined by the Securities and Exchange Commission) also are subject to liability if they fail to take reasonable steps to prevent both of these forms of insider trading.

2    Scope of the Insider Trading Standard

2.1    Who is covered:

1.    This Standard applies to all PG&E Board members, officers, and employees (collectively, the “Insiders”) and to their Related Persons. “Related Persons” include

a.    family members or others who reside with an Insider,

b.    family members who do not reside with an Insider but whose decisions as to their transactions in PG&E securities may be influenced by an Insider, and

c.    partnerships in which the Insider is a general partner, trusts of which an Insider is a trustee, and other legal entities controlled by an Insider.

2.    In addition, other persons who obtain material nonpublic information in the course of their relationship or association with PG&E may be subject to this Standard.

2.2    Securities covered:

1.    This Standard applies to purchases and sales of all types of securities, including common or preferred stock (regardless of whether such securities were acquired in the open market, through stock option exercise, restricted stock vesting, DRSPP contributions, or otherwise), derivative securities (such as put and call options and convertible debentures or preferred stock), and debt securities (such as debentures, bonds, and notes).

2.3    Types of transactions covered:

1.    This Standard applies to making an initial contribution election into the PG&E Corporation Stock Fund within the 401(k) plan, or

2.    changing a contribution election, such as to:

a.    increase or decrease the percentage of a person’s periodic contributions that will be allocated to the PG&E Corporation Stock Fund,

b.    make an intraplan transfer of an existing account balance into or out of the PG&E Corporation Stock Fund,

2

c.    borrow money against person’s 401(k) plan accounts if the loan will result in a liquidation of some or all of a person’s PG&E Corporation Stock Fund balance

d.    pre-pay a 401(k) plan loan if the pre-payment will result in allocation of loan proceeds to the PG&E Corporation Stock Fund;

e.    sell stock upon exercise of a stock option;

f.    make an initial election to participate in the DRSPP, increase the level of participation in the DRSPP, or make additional contributions to the DRSPP.

2.4    Companies covered:

1.    This Standard applies to transactions in:

a.    PG&E securities;

b.    the securities of other companies about which an Insider has learned material nonpublic information regarding in the course of his/her service or employment with PG&E, such as customers or suppliers; and

c.    other companies that are economically linked to PG&E.

3    Trading Blackout

3.1    Quarterly Earnings Blackout Periods. Insiders and others who have access to material nonpublic information relating to PG&E’s quarterly financial results, and their Related Persons, are prohibited from trading in PG&E securities during quarterly earnings blackout periods. The quarterly earnings blackout periods generally begin after market close on the last day of a fiscal quarter and end before market open on the second full trading day following the release of PG&E’s earnings for that quarter; except that the quarterly earnings blackout period for the fourth quarter generally begins after market close on December 17 of each year. For instance, if PG&E releases earnings on a Thursday and there are no holidays, the quarterly earnings blackout period ends before market open on the following Tuesday.

3.2    Event-Specific Blackout Periods. Board members, officers, and employees who have access to information regarding specific material events or developments that have not publicly been disclosed are prohibited from trading in PG&E securities during event-specific trading blackout periods. The event-specific trading blackout periods will be defined by the PG&E Corporation General Counsel or his/her designee (the “Pre-Clearance Officer”).

3.3    Designated Insiders. Those persons who are subject to a quarterly earnings blackout period or event-specific blackout period will be designated by the Pre-Clearance Officer and notified in writing (the “Designated Insiders”). Even if the Pre-Clearance Officer has not notified an Insider that he/she is subject to a trading blackout, such person should not trade while aware of material nonpublic information. The existence of an event-specific trading blackout period or the extension of a quarterly earnings blackout period generally will not be announced to PG&E as a whole and should not be communicated to any other person.

3

3.4    Hardship Exception. A person who is subject to a quarterly earnings blackout period or an event-specific trading blackout period and who faces unforeseen issues as a result of which he/she needs to sell PG&E securities may be permitted to sell PG&E securities during such blackout period only if the Pre-Clearance Officer concludes that such person does not possess material nonpublic information about PG&E.

4    Transactions Pursuant to SEC Rule 10b5-1 Trading Plans and Mandatory 10b5-1 Plan Requirement for Sales

4.1    SEC Rule 10b5-1 provides an affirmative defense from insider trading liability under the federal securities laws for trading plans (“Rule 10b5-1 Plans”) that were entered into or adopted in good faith and when the person was not aware of material nonpublic information.

4.2    All Board members and PG&E officers who are subject to Section 16 of the Securities Exchange Act of 1934 (the “Section 16 officers”) are encouraged to enter into Rule 10b5-1 Plans for any sale or disposition for value in PG&E securities.

4.3    Any Rule 10b5-1 Plan is subject to approval by the Pre-Clearance Officer and must meet the requirements of SEC Rule 10b5-1 and PG&E’s “Guidelines for Rule 10b5-1 Plans” attached in Appendix A. The Pre-Clearance Officer may modify such guidelines as he/she determines necessary or appropriate.

5    Pre-Clearance Requirements

5.1    All Board members, officers, and their Related Persons (collectively, the “Pre-Clearance Persons”) are required to pre-clear any proposed transactions in PG&E securities. In addition, Pre-Clearance Persons are required to pre-clear their dispositions, acquisitions, or transfers of PG&E securities for no consideration including, for example, gifts to a charitable organization, other donations of PG&E securities, a transfer to a family trust, etc. The Pre-Clearance Officer may modify the list of Pre-Clearance Persons as he/she determines necessary or appropriate.

5.2    Pre-clearance procedures are described in Appendix B. The Pre-Clearance Officer may modify such guidelines as he/she determines necessary or appropriate.

6    Material Nonpublic Information

6.1    Material Information. Information is material if there is a substantial likelihood that a reasonable investor would consider it important in deciding whether to buy, hold, or sell a security. Any information that could reasonably be expected to affect the price of the security is material. Some examples of information that may be considered material include:

•financial results, including preliminary and final quarterly and year-end earnings;

•projections of future earnings or losses, or other earnings guidance;

•earnings that are inconsistent with the consensus expectations of the investment community;

•significant developments in rate cases or other major regulatory matters;

4

•significant developments in enforcement matters before the California Public Utilities Commission;

•actual or threatened major litigation or the resolution of such litigation;

•significant cybersecurity incidents;

•a change in executive management;

•changes in dividend or dividend policy;

•a pending or proposed merger, acquisition, or tender offer or an acquisition or disposition of significant assets;

•major events regarding PG&E securities, including the declaration of a stock split or the offering of additional securities;

•severe financial liquidity problems; or

•new major contracts, orders, suppliers, customers, or finance sources, or the loss thereof.

6.2    Nonpublic Information. Information is “nonpublic” if it has not been publicly disclosed. In order for information to be considered “public,” it must be widely disseminated in a manner making it generally available to investors, such as through a press release, an SEC report, or another Regulation FD-compliant method or combination of methods, and the investing public has had time to absorb the information fully. For purposes of this Standard, information generally is considered public after the second full trading day following the release of that information.

6.3    Confidentiality of Material Nonpublic Information. Maintaining the confidentiality of PG&E information is essential for competitive, regulatory, security, and other business reasons, and to comply with securities laws. Insiders should treat all material nonpublic information that they learn about PG&E or its business plans in connection with their employment or other service relationship as confidential and proprietary to PG&E.

7    Additional Restrictions

7.1    PG&E believes that short-term or speculative transactions in PG&E’s securities carry a heightened legal risk and/or the appearance of improper or inappropriate conduct.

7.2    As a result, Board members, officers, and their Related Persons may not engage in:

•short sales of PG&E’s securities (i.e., sales of securities that are not owned at the time of the sale), including a “sale against the box” (generally defined as a sale with delayed delivery);

•transactions in publicly traded options (such as puts, calls, and other derivative securities) on an exchange or in any other organized market relating to PG&E securities;

5

•hedging or monetization transactions involving PG&E securities, such as zero cost collars, forward sale contracts, equity swaps, exchange funds, and other transactions that involve the establishment of a short position in PG&E securities, and limit or eliminate a person’s ability to profit from an increase in the value of PG&E’s securities; and

•holding PG&E securities in a margin account or pledging such securities as collateral for a loan.

8    Post-Termination Transactions

8.1    This Standard continues to apply to an Insider’s transactions in covered securities even after he/she terminates employment with, or other services for, PG&E, if such Insider is in possession of material nonpublic information when his/her employment or service relationship terminates. Such Insider and any of his/her Related Persons may trade after that information has become public or is no longer material.

9    Noncompliance with Insider Trading Laws and the Insider Trading Standard

9.1    Violations of insider trading laws and non-compliance with this Standard may have many adverse consequences, including imprisonment, criminal and civil fines, and PG&E-imposed sanctions, up to and including termination of employment. PG&E, as an employer, also may face enforcement actions.

END of Requirements

    DEFINITIONS

“401(k) plan”: the PG&E Corporation Retirement Savings Plan

“DRSPP”: the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan

“PG&E”: PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries, collectively

6

Appendix A

Guidelines For Rule 10b5-1 Plans

Page 1 of 1

Any Rule 10b5-1 Plan must meet the following guidelines:

•there should be a cooling-off period consisting of at least 90 days but not more than 120 days between the adoption or modification of a Rule 10b5-1 Plan and the first transaction under the new or modified plan;

•if a Rule 10b5-1 Plan is terminated for any reason other than the execution of all the trades or expiration of all the orders relating to such trades set forth in such Rule 10b5-1 Plan, the Insider must wait at least 90 days from the date that the prior plan was terminated before adopting a new plan;

•it should be administered and executed by a PG&E-designated or PG&E-approved broker;

•entering into a Rule 10b5-1 Plan would not cause the Insider to have multiple overlapping Rule 10b5-1 Plans (except as permitted by 17 CFR § 240.10b5-1(c)(1)(ii)(D)):

•entering into a Rule 10b5-1 Plan would not cause the Insider to have adopted more than one single-trade Rule 10b5-1 Plan during any consecutive 12-month period;

•the Rule 10b5-1 Plan does not permit trades to occur during the quarterly earnings blackout period described in Section 3.1;

•it should follow any additional guidelines for Rule 10b5-1 Plans, as determined from time to time by the Pre-Clearance Officer; and

•PG&E and PG&E’s executive officers and directors must make certain disclosures in SEC filings concerning Rule 10b5-1 Plans. Officers and directors of PG&E must undertake to provide any information requested by PG&E regarding Rule 10b5-1 Plans for the purpose of providing the required disclosures or any other disclosures that PG&E deems to be appropriate under the circumstances.

Appendix B

Pre-Clearance Procedures

Page 1 of 1

A request for pre-clearance should be submitted to the Pre-Clearance Officer at least two business days in advance of the proposed transaction. The Pre-Clearance Officer is under no obligation to approve a transaction submitted for pre-clearance. If pre-clearance is denied, such fact must be kept confidential by the Pre-Clearance Person.

Any pre-clearance is valid for five full trading days after it is given by the Pre-Clearance Officer, after which period a new pre-clearance must be obtained if no transaction occurred. Notwithstanding receipt of pre-clearance, if the Pre-Clearance Person becomes aware of material nonpublic information or becomes subject to a quarterly earnings blackout period or an event-specific trading blackout period before the transaction is effected, he/she may not complete the transaction.

Pre-Clearance Persons must continue to pre-clear any proposed transaction in PG&E securities with the Pre-Clearance Officer until the expiration of six months from the termination of service.

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. 333-277286 on Form S-3 ASR and Registration Statements 333-195902, 333-206457, 333-239544, and 333-256896 on Form S-8 of our reports dated February 12, 2025, 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, 2024.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 12, 2025

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-277286-01 on Form S-3 ASR of our reports dated February 12, 2025, 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, 2024.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 12, 2025

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, MARY BIANCHINI, J. ELLEN CONTI, JENNY KAN, and GABRIEL BRIGGS, 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, 2024 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 12th day of February 2025.

/s/ RAJAT BAHRI	/s/ W. CRAIG FUGATE
Rajat Bahri	W. Craig Fugate
/s/ CHERYL F. CAMPBELL	/s/ ARNO L. HARRIS
Cheryl F. Campbell	Arno L. Harris
/s/ EDWARD G. CANNIZZARO	/s/ CARLOS M. HERNANDEZ
Edward G. Cannizzaro	Carlos M. Hernandez
/s/ KERRY W. COOPER	/s/ PATRICIA K. POPPE
Kerry W. Cooper	Patrica K. Poppe

/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/ MICHAEL R. NIGGLI
Michael R. Niggli

POWER OF ATTORNEY

         Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints JOHN R. SIMON, BRIAN M. WONG, MARY BIANCHINI, J. ELLEN CONTI, JENNY KAN, and GABRIEL BRIGGS, 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, 2024 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 12th day of February 2025.

/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/ EDWARD G. CANNIZZARO	/s/ MICHAEL R. NIGGLI
Edward G. Cannizzaro	Michael R. Niggli
/s/ KERRY W. COOPER	/s/ PATRICIA K. POPPE
Kerry W. Cooper	Patricia K. Poppe

/s/ JESSICA L. DENECOUR	/s/ SUMEET SINGH
Jessica L. Denecour	Sumeet Singh
/s/ MARK E. FERGUSON III	/s/ WILLIAM L. SMITH
Mark E. Ferguson III	William L. Smith
/s/ W. CRAIG FUGATE	/s/ BENJAMIN F. WILSON
W. Craig Fugate	Benjamin F. Wilson

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, 2024 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 12, 2025	/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, Carolyn J. Burke, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2024 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 12, 2025	/s/ CAROLYN J. BURKE
	Carolyn J. Burke
	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, Sumeet Singh, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2024 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 12, 2025	/s/ SUMEET SINGH
	Sumeet Singh
	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, 2024 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 12, 2025	/s/ MARLENE M. SANTOS
	Marlene M. Santos
	Executive Vice President and Chief Customer and Enterprise Solutions 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, 2024 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 12, 2025	/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, 2024 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 12, 2025	/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, 2024 (“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 12, 2025

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, 2024 (“Form 10-K”), I, Carolyn J. Burke, 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/ CAROLYN J. BURKE

Carolyn J. Burke

Executive Vice President and Chief Financial Officer

February 12, 2025

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, 2024 (“Form 10-K”), I, Sumeet Singh, 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/ SUMEET SINGH

Sumeet Singh

Executive Vice President, Operations and Chief Operating Officer

February 12, 2025

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, 2024 (“Form 10-K”), I, Marlene M. Santos, Executive Vice President and Chief Customer and Enterprise Solutions 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 and Enterprise Solutions Officer

February 12, 2025

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, 2024 (“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 12, 2025

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, 2024 (“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 12, 2025

XML

Audit Information	12 Months Ended
	Dec. 31, 2024
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, 2024

Feb. 05, 2025

Jun. 30, 2024

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2024

Current Fiscal Year End Date

--12-31

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

Document Financial Statement Error Correction [Flag]

false

Entity Shell Company

false

Entity Bankruptcy Proceedings, Reporting Current

true

Entity Public Float

$ 45,624

Entity Common Stock, Shares Outstanding (in shares)

2,671,320,389

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 2025 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Amendment Flag

false

Document Fiscal Year Focus

2024

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

973-7000

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

Document Financial Statement Error Correction [Flag]

false

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 2025 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 | 6.000% Series A Mandatory Convertible Preferred Stock, no par value

Title of 12(b) Security

6.000% Series A Mandatory Convertible Preferred Stock, no par value

Trading Symbol

PCG-PrX

Security Exchange Name

NYSE

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

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, 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, 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

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Revenues
Total operating revenues	$ 24,419	$ 24,428	$ 21,680
Operating Expenses
Operating and maintenance	11,808	11,924	9,809
SB 901 securitization charges, net	33	1,267	608
Wildfire-related claims, net of recoveries	94	64	237
Wildfire Fund expense	383	567	477
Depreciation, amortization, and decommissioning	4,189	3,738	3,856
Total operating expenses	19,960	21,757	19,843
Operating Income	4,459	2,671	1,837
Interest income	604	606	162
Interest expense	(3,051)	(2,850)	(1,917)
Other income, net	300	272	394
Income Before Income Taxes	2,312	699	476
Income tax benefit	(200)	(1,557)	(1,338)
Net Income	2,512	2,256	1,814
Preferred stock dividend requirement	37	14	14
Income Available for Common Shareholders	2,475	2,242	1,800
Income Available for Common Shareholders	$ 2,475	$ 2,242	$ 1,800
Weighted Average Common Shares Outstanding, Basic (in shares)	2,141	2,064	1,987
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,147	2,138	2,132
Net Income Per Common Share, Basic (in dollars per share)	$ 1.16	$ 1.09	$ 0.91
Net Income Per Common Share, Diluted (in dollars per share)	$ 1.15	$ 1.05	$ 0.84
Electric
Operating Revenues
Total operating revenues	$ 17,811	$ 17,424	$ 15,060
Operating Expenses
Cost of electricity and natural gas	2,261	2,443	2,756
Natural gas
Operating Revenues
Total operating revenues	6,608	7,004	6,620
Operating Expenses
Cost of electricity and natural gas	$ 1,192	$ 1,754	$ 2,100

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income	$ 2,512	$ 2,256	$ 1,814
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)	(16)	21
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $3, and $3, respectively)	1	8	(6)
Total other comprehensive income (loss)	(6)	(8)	15
Comprehensive Income	2,506	2,248	1,829
Preferred stock dividend requirement of subsidiary	37	14	14
Comprehensive Income Attributable to Common Shareholders	$ 2,469	$ 2,234	$ 1,815

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 6	$ 8
Net unrealized losses on available for sale securities, tax	$ 0	$ 3	$ 3

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current Assets
Cash and cash equivalents	$ 940	$ 635
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	273	297
Accounts receivable
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Regulatory balancing accounts	7,227	5,660
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	1,810	1,494
Regulatory assets	234	300
Inventories
Gas stored underground and fuel oil	52	65
Materials and supplies	768	805
Wildfire Fund asset	301	450
Wildfire self-insurance asset	905	0
Other	999	1,375
Total current assets	17,216	14,383
Property, Plant, and Equipment
Electric	86,639	80,345
Gas	31,623	29,830
Construction work in progress	4,458	4,452
Financing lease ROU asset and other	814	787
Total property, plant, and equipment	123,534	115,414
Accumulated depreciation	(35,305)	(33,093)
Net property, plant, and equipment	88,229	82,321
Other Noncurrent Assets
Regulatory assets	15,561	17,189
Customer credit trust	377	233
Nuclear decommissioning trusts	3,833	3,574
Operating lease ROU asset	524	598
Wildfire Fund asset	4,070	4,297
Income taxes receivable	1	24
Other (includes noncurrent accounts receivable of $82 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $18 million and $0 at respective dates)	3,849	3,079
Total other noncurrent assets	28,215	28,994
TOTAL ASSETS	133,660	125,698
Current Liabilities
Short-term borrowings	1,523	3,971
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Accounts payable
Trade creditors	2,748	2,309
Regulatory balancing accounts	3,169	1,669
Other	748	851
Operating lease liabilities	85	80
Financing lease liabilities	577	259
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	760	679
Wildfire-related claims	916	1,422
Other	3,658	4,698
Total current liabilities	16,330	17,314
Noncurrent Liabilities
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	53,569	50,975
Regulatory liabilities	19,417	19,444
Pension and other postretirement benefits	808	476
Asset retirement obligations	5,444	5,512
Deferred income taxes	3,082	1,980
Operating lease liabilities	439	518
Financing lease liabilities	4	554
Other	4,166	3,633
Total noncurrent liabilities	86,929	83,092
Shareholders’ Equity
Mandatory convertible preferred stock	1,579	0
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,193,573,536 and 2,133,597,758 shares outstanding at respective dates	31,555	30,374
Reinvested earnings	(2,966)	(5,321)
Accumulated other comprehensive loss	(19)	(13)
Total shareholders’ equity	30,149	25,040
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	30,401	25,292
TOTAL LIABILITIES AND EQUITY	$ 133,660	$ 125,698

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	$ 273	$ 297	$ 213
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	35	35
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	760	679
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	$ 53,569	$ 50,975
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)	2,193,573,536	2,133,597,758
Variable Interest Entity, Primary Beneficiary
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	$ 263	$ 282
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	1,900	1,700
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,300	1,100
Noncurrent accounts receivable	82	0
Allowance for doubtful accounts, noncurrent	18	0
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	222	176
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	91	67
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	$ 10,100	$ 10,500

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash Flows from Operating Activities
Net income	$ 2,512	$ 2,256	$ 1,814
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,189	3,738	3,856
Bad debt expense	341	636	143
Allowance for equity funds used during construction	(184)	(179)	(184)
Deferred income taxes and tax credits, net	1,098	(765)	(452)
Wildfire Fund expense	383	568	477
Disallowed capital expenditures	0	0	15
Other	310	(116)	517
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,061)	(369)	(757)
Wildfire-related insurance receivable	318	358	453
Inventories	45	(28)	(246)
Accounts payable	30	(90)	627
Wildfire-related claims	(506)	(489)	(810)
Other current assets and liabilities	(231)	397	17
Regulatory assets, liabilities, and balancing accounts, net	1,545	(429)	(1,131)
Contributions to Wildfire Fund	(193)	(193)	(193)
Other noncurrent assets and liabilities	(561)	(548)	(425)
Net cash provided by operating activities	8,035	4,747	3,721
Cash Flows from Investing Activities
Capital expenditures	(10,369)	(9,714)	(9,584)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,980	2,235	3,316
Purchases of nuclear decommissioning trust investments	(2,002)	(2,252)	(3,208)
Proceeds from sales and maturities of customer credit trust investments	398	556	250
Purchases of customer credit investments	(519)	0	(1,022)
Purchases of self-insurance investments	(898)	0	0
Other	35	13	34
Net cash used in investing activities	(11,375)	(9,162)	(10,214)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,873	10,675	10,130
Repayments under credit facilities	(10,122)	(10,540)	(9,750)
Borrowings under term loan credit facilities	0	2,100	0
Repayments under term loan credit facilities	(2,600)	(2,181)	0
Short-term borrowings, net of issuance costs of $1, $0, and $0 at respective dates	999	0	0
Short-term debt matured	0	0	(300)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $5, $67, and $29 at respective dates	4,495	5,483	4,271
Repayments of long-term debt	(800)	(3,075)	(5,968)
Proceeds from DWR loan	980	0	312
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates	0	2,123	0
Mandatory convertible preferred stock issued	1,579	0	0
Common stock issued	1,128	0	0
Common stock dividends paid	(86)	0	0
Other	(59)	(17)	53
Net cash provided by financing activities	3,621	4,400	7,133
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	281	(15)	640
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	932	947	307
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	1,213	932	947
Less: Restricted cash and restricted cash equivalents	(273)	(297)	(213)
Cash and cash equivalents at December 31	940	635	734
Supplemental disclosures of cash flow information Cash paid for:
Interest, net of amounts capitalized	(2,421)	(2,286)	(1,607)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,144	1,105	1,174
Operating lease liabilities arising from ROU assets	6	269	529
Financing lease liabilities arising from obtaining ROU assets	43	52	0
Reclassification of operating lease liabilities to financing lease liabilities	0	913	0
DWR loan forgiveness and performance-based disbursements	192	214	0
Changes to PG&E Corporation common stock and treasury stock in connection with share exchanges with the Fire Victim Trust	0	(2,517)	(2,337)
Dividends declared but not yet paid	55	21	0
Mandatory convertible preferred stock
Supplemental disclosures of noncash investing and financing activities
Dividends declared but not yet paid	23	0	0
SB 901 securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	0	0	7,464
Repayments of recovery bonds	(129)	(130)	(33)
AB 1054 Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	1,409	0	972
Repayments of recovery bonds	$ (46)	$ (38)	$ (18)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Issuance costs for short-term debt	$ 1	$ 0	$ 0
Premium, discount, and issuance costs on proceeds from long-term debt	5	67	29
SB 901 securitization
Financing fees	0	0	36
AB 1054 Recovery Bonds
Financing fees	10	0	11
Convertible Notes Due 2027
Premium, discount, and issuance costs on proceeds from long-term debt	$ 0	$ 27	$ 0

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CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total Shareholders' Equity	Preferred Stock	Common Stock	Treasury Stock	Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)	Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance at Dec. 31, 2021	$ 21,223	$ 20,971	$ 0	$ 35,129	$ (4,854)	$ (9,284)	$ (20)	$ 252
Beginning balance (in shares) at Dec. 31, 2021				1,985,400,540
Beginning balance, treasury (in shares) at Dec. 31, 2021					477,743,590,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	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)					(230,000,000,000,000)
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 at Dec. 31, 2022	23,075	22,823	0	$ 32,887	$ (2,517)	(7,542)	(5)	252
Ending balance (in shares) at Dec. 31, 2022				1,987,784,948
Ending balance, treasury (in shares) at Dec. 31, 2022					247,743,590
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,256	2,256				2,256
Other comprehensive income (loss)	(8)	(8)					(8)
Common stock issued, net (in shares)				145,812,810
Common stock issued, net	(2,517)	(2,517)		$ (2,517)
Treasury stock disposition (in shares)					(247,743,590)
Treasury stock disposition	2,517	2,517			$ 2,517
Stock-based compensation amortization	4	4		4
Preferred stock dividend requirement of subsidiary	(14)	(14)				(14)
Common stock dividends declared	(21)	(21)				(21)
Ending balance at Dec. 31, 2023	$ 25,292	25,040	0	$ 30,374	$ 0	(5,321)	(13)	252
Ending balance (in shares) at Dec. 31, 2023	2,133,597,758			2,133,597,758
Ending balance, treasury (in shares) at Dec. 31, 2023					0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 2,512	2,512				2,512
Other comprehensive income (loss)	(6)	(6)					(6)
Preferred Stock issued, net	1,579	1,579	1,579
Common stock issued, net (in shares)				59,975,778
Common stock issued, net	1,128	1,128		$ 1,128
Stock-based compensation amortization	53	53		53
Preferred stock dividend requirement of subsidiary	(37)	(37)				(37)
Common stock dividends declared	(120)	(120)				(120)
Ending balance at Dec. 31, 2024	$ 30,401	$ 30,149	$ 1,579	$ 31,555	$ 0	$ (2,966)	$ (19)	$ 252
Ending balance (in shares) at Dec. 31, 2024	2,193,573,536			2,193,573,536
Ending balance, treasury (in shares) at Dec. 31, 2024					0

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CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Revenues
Total operating revenues	$ 24,419.0	$ 24,428.0	$ 21,680.0
Operating Expenses
Operating and maintenance	11,808.0	11,924.0	9,809.0
SB 901 securitization charges, net	33.0	1,267.0	608.0
Wildfire-related claims, net of recoveries	94.0	64.0	237.0
Wildfire Fund expense	383.0	567.0	477.0
Depreciation, amortization, and decommissioning	4,189.0	3,738.0	3,856.0
Total operating expenses	19,960.0	21,757.0	19,843.0
Operating Income	4,459.0	2,671.0	1,837.0
Interest income	604.0	606.0	162.0
Interest expense	(3,051.0)	(2,850.0)	(1,917.0)
Other income, net	300.0	272.0	394.0
Income Before Income Taxes	2,312.0	699.0	476.0
Income tax benefit	(200.0)	(1,557.0)	(1,338.0)
Net Income	2,512.0	2,256.0	1,814.0
Preferred stock dividend requirement	37.0	14.0	13.0
Income Available for Common Shareholders	2,475.0	2,242.0	1,800.0
Income Available for Common Shareholders	2,475.0	2,242.0	1,800.0
Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	24,419.0	24,428.0	21,680.0
Operating Expenses
Operating and maintenance	11,787.0	11,913.0	9,725.0
SB 901 securitization charges, net	33.0	1,267.0	608.0
Wildfire-related claims, net of recoveries	94.0	64.0	237.0
Wildfire Fund expense	383.0	567.0	477.0
Depreciation, amortization, and decommissioning	4,189.0	3,738.0	3,856.0
Total operating expenses	19,939.0	21,746.0	19,759.0
Operating Income	4,480.0	2,682.0	1,921.0
Interest income	589.0	593.0	162.0
Interest expense	(2,781.0)	(2,485.0)	(1,658.0)
Other income, net	319.0	293.0	595.0
Income Before Income Taxes	2,607.0	1,083.0	1,020.0
Income tax benefit	(105.0)	(1,461.0)	(1,206.0)
Net Income	2,712.0	2,544.0	2,226.0
Preferred stock dividend requirement	14.0	14.0	14.0
Income Available for Common Shareholders	2,698.0	2,530.0	2,212.0
Income Available for Common Shareholders	2,698.0	2,530.0	2,212.0
Electric
Operating Revenues
Total operating revenues	17,811.0	17,424.0	15,060.0
Operating Expenses
Cost of electricity and natural gas	2,261.0	2,443.0	2,756.0
Electric | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	17,811.0	17,424.0	15,060.0
Operating Expenses
Cost of electricity and natural gas	2,261.0	2,443.0	2,756.0
Natural gas
Operating Revenues
Total operating revenues	6,608.0	7,004.0	6,620.0
Operating Expenses
Cost of electricity and natural gas	1,192.0	1,754.0	2,100.0
Natural gas | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	6,608.0	7,004.0	6,620.0
Operating Expenses
Cost of electricity and natural gas	$ 1,192.0	$ 1,754.0	$ 2,100.0

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Net income	$ 2,512	$ 2,256	$ 1,814
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $5, and $2, at respective dates)	(7)	(16)	21
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $4, and $3, respectively)	1	8	(6)
Total other comprehensive income (loss)	(6)	(8)	15
Comprehensive Income	2,506	2,248	1,829
Pacific Gas & Electric Co (Utility)
Net income	2,712	2,544	2,226
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $5, and $2, at respective dates)	(8)	(12)	6
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $4, and $3, respectively)	1	7	(5)
Total other comprehensive income (loss)	(7)	(5)	1
Comprehensive Income	$ 2,705	$ 2,539	$ 2,227

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 6	$ 8
Net unrealized losses on available for sale securities, tax	0	3	3
Pacific Gas & Electric Co (Utility)
Pension and other postretirement benefit plans obligations, tax	3	5	2
Net unrealized losses on available for sale securities, tax	$ 0	$ 4	$ 3

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CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current Assets
Cash and cash equivalents	$ 940	$ 635
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	273	297
Accounts receivable
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Regulatory balancing accounts	7,227	5,660
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	1,810	1,494
Regulatory assets	234	300
Inventories
Gas stored underground and fuel oil	52	65
Materials and supplies	768	805
Wildfire Fund asset	301	450
Wildfire self-insurance asset	905	0
Other	999	1,375
Total current assets	17,216	14,383
Property, Plant, and Equipment
Electric	86,639	80,345
Gas	31,623	29,830
Construction work in progress	4,458	4,452
Financing lease ROU asset and other	814	787
Total property, plant, and equipment	123,534	115,414
Accumulated depreciation	(35,305)	(33,093)
Net property, plant, and equipment	88,229	82,321
Other Noncurrent Assets
Regulatory assets	15,561	17,189
Customer credit trust	377	233
Nuclear decommissioning trusts	3,833	3,574
Operating lease ROU asset	524	598
Wildfire Fund asset	4,070	4,297
Income taxes receivable	1	24
Other (includes noncurrent accounts receivable of $82 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $18 million and $0 at respective dates)	3,849	3,079
Total other noncurrent assets	28,215	28,994
TOTAL ASSETS	133,660	125,698
Current Liabilities
Short-term borrowings	1,523	3,971
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Accounts payable
Trade creditors	2,748	2,309
Regulatory balancing accounts	3,169	1,669
Other	748	851
Operating lease liabilities	85	80
Financing lease liabilities	577	259
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	760	679
Wildfire-related claims	916	1,422
Other	3,658	4,698
Total current liabilities	16,330	17,314
Noncurrent Liabilities
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	53,569	50,975
Regulatory liabilities	19,417	19,444
Pension and other postretirement benefits	808	476
Asset retirement obligations	5,444	5,512
Deferred income taxes	3,082	1,980
Operating lease liabilities	439	518
Financing lease liabilities	4	554
Other	4,166	3,633
Total noncurrent liabilities	86,929	83,092
Shareholders’ Equity
Preferred stock	1,579	0
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates	31,555	30,374
Reinvested earnings	(2,966)	(5,321)
Accumulated other comprehensive loss	(19)	(13)
Total shareholders’ equity	30,149	25,040
TOTAL LIABILITIES AND EQUITY	133,660	125,698
Pacific Gas & Electric Co (Utility)
Current Assets
Cash and cash equivalents	705	442
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	272	294
Accounts receivable
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Regulatory balancing accounts	7,227	5,660
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	1,810	1,495
Regulatory assets	234	300
Inventories
Gas stored underground and fuel oil	52	65
Materials and supplies	768	805
Wildfire Fund asset	301	450
Wildfire self-insurance asset	905	0
Other	998	1,374
Total current assets	16,979	14,187
Property, Plant, and Equipment
Electric	86,639	80,345
Gas	31,623	29,830
Construction work in progress	4,458	4,452
Financing lease ROU asset and other	814	787
Total property, plant, and equipment	123,534	115,414
Accumulated depreciation	(35,304)	(33,093)
Net property, plant, and equipment	88,230	82,321
Other Noncurrent Assets
Regulatory assets	15,561	17,189
Customer credit trust	377	233
Nuclear decommissioning trusts	3,833	3,574
Operating lease ROU asset	519	598
Wildfire Fund asset	4,070	4,297
Income taxes receivable	0	22
Other (includes noncurrent accounts receivable of $82 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $18 million and $0 at respective dates)	3,697	2,934
Total other noncurrent assets	28,057	28,847
TOTAL ASSETS	133,266	125,355
Current Liabilities
Short-term borrowings	1,523	3,971
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Accounts payable
Trade creditors	2,745	2,307
Regulatory balancing accounts	3,169	1,669
Other	729	820
Operating lease liabilities	85	80
Financing lease liabilities	577	259
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	667	621
Wildfire-related claims	916	1,422
Other	3,331	4,391
Total current liabilities	15,888	16,916
Noncurrent Liabilities
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	47,958	46,376
Regulatory liabilities	19,417	19,444
Pension and other postretirement benefits	741	405
Asset retirement obligations	5,444	5,512
Deferred income taxes	3,632	2,436
Operating lease liabilities	434	518
Financing lease liabilities	4	554
Other	4,198	3,670
Total noncurrent liabilities	81,828	78,915
Shareholders’ Equity
Preferred stock	258	258
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates	1,322	1,322
Additional paid-in capital	35,930	30,570
Reinvested earnings	(1,940)	(2,613)
Accumulated other comprehensive loss	(20)	(13)
Total shareholders’ equity	35,550	29,524
TOTAL LIABILITIES AND EQUITY	$ 133,266	$ 125,355

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	$ 273	$ 297
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	35	35
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	760	679
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	$ 53,569	$ 50,975
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)	2,193,573,536	2,133,597,758
Pacific Gas & Electric Co (Utility)
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	$ 272	$ 294
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	2,220	2,048
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,487	1,254
Other (net of allowance for doubtful accounts of $35 million and $35 million at respective dates)	35	35
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	2,146	1,376
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	667	621
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	$ 47,958	$ 46,376
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)	800,000,000	800,000,000
Variable Interest Entity, Primary Beneficiary
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	$ 263	$ 282
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	1,900	1,700
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,300	1,100
Allowance for doubtful accounts, noncurrent	18	0
Noncurrent accounts receivable	82	0
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	222	176
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	91	67
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	10,100	10,500
Variable Interest Entity, Primary Beneficiary | Pacific Gas & Electric Co (Utility)
Restricted cash and restricted cash equivalents (includes $263 million and $282 million related to VIEs at respective dates)	263	282
Allowance for doubtful accounts	418	445
Customers (net of allowance for doubtful accounts of $418 million and $445 million at respective dates) (includes $1.9 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $418 million and $445 million at respective dates)	1,900	1,700
Accrued unbilled revenue (includes $1.3 billion and $1.1 billion related to VIEs at respective dates)	1,300	1,100
Allowance for doubtful accounts, noncurrent	82	0
Noncurrent accounts receivable	18	0
Long-term debt, classified as current (includes $222 million and $176 million related to VIEs at respective dates)	222	176
Interest payable (includes $91 million and $67 million related to VIEs at respective dates)	91	67
Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	$ 10,100	$ 10,500

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CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash Flows from Operating Activities
Net income	$ 2,512	$ 2,256	$ 1,814
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,189	3,738	3,856
Bad debt expense	341	636	143
Allowance for equity funds used during construction	(184)	(179)	(184)
Deferred income taxes and tax credits, net	1,098	(765)	(452)
Wildfire Fund expense	383	568	477
Disallowed capital expenditures	0	0	15
Other	310	(116)	517
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,061)	(369)	(757)
Wildfire-related insurance receivable	318	358	453
Inventories	45	(28)	(246)
Accounts payable	30	(90)	627
Wildfire-related claims	(506)	(489)	(810)
Other current assets and liabilities	(231)	397	17
Regulatory assets, liabilities, and balancing accounts, net	1,545	(429)	(1,131)
Contributions to Wildfire Fund	(193)	(193)	(193)
Other noncurrent assets and liabilities	(561)	(548)	(425)
Net cash provided by operating activities	8,035	4,747	3,721
Cash Flows from Investing Activities
Capital expenditures	(10,369)	(9,714)	(9,584)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,980	2,235	3,316
Purchases of nuclear decommissioning trust investments	(2,002)	(2,252)	(3,208)
Proceeds from sales and maturities of customer credit trust investments	398	556	250
Purchases of customer credit investments	(519)	0	(1,022)
Purchases of self-insurance investments	(898)	0	0
Other	35	13	34
Net cash used in investing activities	(11,375)	(9,162)	(10,214)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,873	10,675	10,130
Repayments under credit facilities	(10,122)	(10,540)	(9,750)
Borrowings under term loan credit facilities	0	2,100	0
Repayments under term loan credit facilities	(2,600)	(2,181)	0
Short-term borrowings, net of issuance costs of $1, $0, and $0 at respective dates	999	0	0
Short-term debt matured	0	0	(300)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $1, $67, and $29 at respective dates	4,495	5,483	4,271
Repayments of long-term debt	(800)	(3,075)	(5,968)
Proceeds from DWR loan	980	0	312
Common stock dividends paid	(86)	0	0
Other	(59)	(17)	53
Net cash provided by financing activities	3,621	4,400	7,133
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	281	(15)	640
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	932	947	307
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	1,213	932	947
Less: Restricted cash and restricted cash equivalents	(273)	(297)	(213)
Cash and cash equivalents at December 31	940	635	734
Supplemental disclosures of cash flow information Cash paid for:
Interest, net of amounts capitalized	(2,421)	(2,286)	(1,607)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,144	1,105	1,174
Operating lease liabilities arising from obtaining ROU assets	6	269	529
Financing lease liabilities arising from obtaining ROU assets	43	52	0
Reclassification of operating lease liabilities to financing lease liabilities	0	913	0
DWR loan forgiveness and performance-based disbursements	192	214	0
SB 901 securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	0	0	7,464
Repayments of recovery bonds	(129)	(130)	(33)
AB 1054 Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	1,409	0	972
Repayments of recovery bonds	(46)	(38)	(18)
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net income	2,712	2,544	2,226
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,189	3,738	3,856
Bad debt expense	341	636	143
Allowance for equity funds used during construction	(184)	(179)	(184)
Deferred income taxes and tax credits, net	1,195	(663)	(319)
Wildfire Fund expense	383	568	477
Disallowed capital expenditures	0	0	15
Other	233	(176)	102
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,060)	(361)	(763)
Wildfire-related insurance receivable	318	358	453
Inventories	45	(28)	(246)
Accounts payable	44	(90)	627
Wildfire-related claims	(506)	(489)	(810)
Other current assets and liabilities	(235)	402	16
Regulatory assets, liabilities, and balancing accounts, net	1,545	(429)	(1,131)
Contributions to Wildfire Fund	(193)	(193)	(193)
Other noncurrent assets and liabilities	(559)	(541)	(438)
Net cash provided by operating activities	8,268	5,097	3,831
Cash Flows from Investing Activities
Capital expenditures	(10,369)	(9,714)	(9,584)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,980	2,235	3,316
Purchases of nuclear decommissioning trust investments	(2,002)	(2,252)	(3,208)
Proceeds from sales and maturities of customer credit trust investments	398	556	250
Purchases of customer credit investments	(519)	0	(1,022)
Proceeds from intercompany note to PG&E Corporation	0	0	145
Purchases of self-insurance investments	(898)	0	0
Other	35	13	34
Net cash used in investing activities	(11,375)	(9,162)	(10,069)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,873	10,675	10,130
Repayments under credit facilities	(10,122)	(10,540)	(9,750)
Borrowings under term loan credit facilities	0	2,100	0
Repayments under term loan credit facilities	(2,100)	0	0
Short-term borrowings, net of issuance costs of $1, $0, and $0 at respective dates	999	0	0
Short-term debt matured	0	0	(300)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $1, $67, and $29 at respective dates	2,999	5,483	4,271
Repayments of long-term debt	(800)	(3,075)	(5,941)
Proceeds from DWR loan	980	0	312
Preferred stock dividends paid	(14)	(14)	(70)
Common stock dividends paid	(2,025)	(1,775)	(1,275)
Equity contribution from PG&E Corporation	5,360	1,290	994
Other	(36)	3	123
Net cash provided by financing activities	3,348	3,979	6,879
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	241	(86)	641
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	736	822	181
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	977	736	822
Less: Restricted cash and restricted cash equivalents	(272)	(294)	(213)
Cash and cash equivalents at December 31	705	442	609
Supplemental disclosures of cash flow information Cash paid for:
Interest, net of amounts capitalized	(2,206)	(1,977)	(1,374)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,144	1,105	1,174
Operating lease liabilities arising from obtaining ROU assets	1	269	529
Financing lease liabilities arising from obtaining ROU assets	43	52	0
Reclassification of operating lease liabilities to financing lease liabilities	0	913	0
DWR loan forgiveness and performance-based disbursements	192	214	0
Pacific Gas & Electric Co (Utility) | SB 901 securitization
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	0	0	7,464
Repayments of recovery bonds	(129)	(130)	(33)
Pacific Gas & Electric Co (Utility) | AB 1054 Recovery Bonds
Cash Flows from Financing Activities
Proceeds from issuance of recovery bonds, net of financing fees at respective dates	1,409	0	972
Repayments of recovery bonds	$ (46)	$ (38)	$ (18)

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CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Issuance costs for short-term debt	$ 1	$ 0	$ 0
Premium, discount, and issuance costs on proceeds from long-term debt	5	67	29
SB 901 securitization
Financing fees	0	0	36
AB 1054 Recovery Bonds
Financing fees	10	0	11
Pacific Gas & Electric Co (Utility)
Issuance costs for short-term debt	1	0	0
Premium, discount, and issuance costs on proceeds from long-term debt	1	67	29
Pacific Gas & Electric Co (Utility) | SB 901 securitization
Financing fees	0	0	36
Pacific Gas & Electric Co (Utility) | AB 1054 Recovery Bonds
Financing fees	$ 10	$ 0	$ 11

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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	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, 2021	$ 21,223		$ 20,971	$ 25,610	$ 0	$ 258	$ 35,129	$ 1,322	$ 28,286	$ (9,284)	$ (4,247)	$ (20)	$ (9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	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 in arrears	(59)		(59)	(59)						(59)	(59)
Preferred stock dividend requirement				(13)							(13)
Common stock dividend				(1,275)							(1,275)
Ending balance at Dec. 31, 2022	23,075		22,823	27,484	0	258	32,887	1,322	29,280	(7,542)	(3,368)	(5)	(8)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,256	2,544	2,256	2,544						2,256	2,544
Other comprehensive income (loss)	(8)	(5)	(8)	(5)								(8)	(5)
Equity contribution				1,290					1,290
Preferred stock dividend requirement				(14)							(14)
Common stock dividend	(21)		(21)	(1,775)						(21)	(1,775)
Ending balance at Dec. 31, 2023	25,292		25,040	29,524	0	258	30,374	1,322	30,570	(5,321)	(2,613)	(13)	(13)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,512	2,712	2,512	2,712						2,512	2,712
Other comprehensive income (loss)	(6)	$ (7)	(6)	(7)								(6)	(7)
Equity contribution				5,360					5,360
Preferred stock dividend requirement				(14)							(14)
Common stock dividend	(120)		(120)	(2,025)						(120)	(2,025)
Ending balance at Dec. 31, 2024	$ 30,401		$ 30,149	$ 35,550	$ 1,579	$ 258	$ 31,555	$ 1,322	$ 35,930	$ (2,966)	$ (1,940)	$ (19)	$ (20)

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ORGANIZATION AND BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2024

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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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2024

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.

Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the chief operating decision maker uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.

Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2024 and 2023, the Utility also held $272 million and $294 million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

As of December 31, 2024, the Utility had contributed $911 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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 through 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)	2024		2023		2022
Electric
Revenue from contracts with customers
Residential	$	7,504	$	6,041	$	6,130
Commercial	7,201		5,643		5,416
Industrial	2,065		1,784		1,626
Agricultural	1,815		1,413		1,830
Public street and highway lighting	103		83		77
Other, net (1)	(47)		136		(247)
Total revenue from contracts with customers - electric	18,641		15,100		14,832
Regulatory balancing accounts (2)	(830)		2,324		228
Total electric operating revenue	$	17,811	$	17,424	$	15,060
Natural gas
Revenue from contracts with customers
Residential	$	3,089	$	3,686	$	3,353
Commercial	984		1,052		1,005
Transportation service only	1,815		1,603		1,534
Other, net (1)	159		(145)		163
Total revenue from contracts with customers - gas	6,047		6,196		6,055
Regulatory balancing accounts (2)	561		808		565
Total natural gas operating revenue	6,608		7,004		6,620
Total operating revenues	$	24,419	$	24,428	$	21,680

(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 alternative 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, 2024, 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.

Expected credit losses of $341 million, $636 million, and $143 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2024, 2023, and 2022, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively. As of December 31, 2023, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $507 million and $78 million, respectively. The RUBA current balancing account balance decreased from December 31, 2023 to December 31, 2024 primarily due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

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. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. 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, 2024, 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 for use 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 allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” 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)	2024		2023
Electricity generating facilities (1)	1 to 75	$	11,420	$	11,423
Electricity distribution facilities	10 to 70	49,821		45,205
Electricity transmission facilities	15 to 75	18,481		17,562
Natural gas distribution facilities	15 to 60	17,213		16,324
Natural gas transmission and storage facilities	15 to 68	11,117		10,496
General plant and other	5 to 50	10,210		9,165
Financing lease		814		787
Construction work in progress		4,458		4,452
Total property, plant, and equipment		123,534		115,414
Accumulated depreciation		(35,304)		(33,093)
Net property, plant, and equipment (2)		$	88,230	$	82,321

(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below. Nuclear generating facilities have been authorized by the CPUC to be fully depreciated by December 31, 2025.

(2) Includes $3.0 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.

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 in 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 3.61% in 2024, 3.56% in 2023, and 3.74% in 2022.  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.

Allowance for Funds Used During Construction

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 $111 million and $184 million during 2024, $82 million and $179 million during 2023, and $81 million and $184 million during 2022.

Asset Retirement Obligations

The following table summarizes the changes in ARO during 2024 and 2023, including nuclear decommissioning obligations:

(in millions)	2024		2023
ARO liability at beginning of year	$	5,512	$	5,912
Revision in estimated cash flows	(290)		(585)
Accretion	269		253
Liabilities settled	(47)		(68)
ARO liability at end of year	$	5,444	$	5,512

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 3 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 estimated decommissioning dates. 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 cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, 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 plant. 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 using a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2024 and December 31, 2023 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2024, the Utility recorded a $222 million reduction to the nuclear decommissioning ARO to reflect the NRC’s decision to grant DCPP’s extended operations until 2030. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

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 DCPP and the Humboldt Bay independent spent fuel storage installation.  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.

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

The Utility participated in various government assistance programs during the years ended December 31, 2024, 2023, and 2022. 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, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, 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. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, 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 pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for DCPP Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of DCPP. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility received the final proceeds from the DWR loan agreement in 2024. For more information, see the DWR loan activity table below.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:

(in millions)	2024		2023		2022
Long-term debt:
Beginning Balance - DWR loan outstanding	$	98	$	312	$	—
Proceeds received	980		—		350
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(117)		(124)		(38)
Operating and maintenance expense - Loan forgiveness and other adjustments	(75)		(90)		—
Long-term debt:
Ending Balance - DWR loan outstanding	$	886	$	98	$	312

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are 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 a number of factors, including actual costs incurred to extend the DCPP operations. 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 recognizes such funding as income and records a receivable related to government grants. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $265 million and $115 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $138 million and $76 million, as a deduction to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP.

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 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2024 and December 31, 2023, the SPV had net accounts receivable of $3.2 billion and $2.7 billion, respectively, and outstanding borrowings of zero and $1.5 billion respectively, under the Receivables Securitization Program. For more information, see Note 4 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 orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Recovery Funding LLC had outstanding borrowings of $3.2 billion and $1.8 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets.

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 first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.2 billion and $7.3 billion 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.

Non-Consolidated VIEs

Power Purchase Agreements

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, 2024, the Utility 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, 2024, it did not consolidate any of them.

The Lakeside Building

BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building, which serves as the Utility’s principal administrative headquarters.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property, and the Utility does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to an issued letter of credit, base rent, and certain costs it pays according to the office lease agreement. As a result, the Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC. For more information, see “Oakland Headquarters Lease and Purchase” in Note 15 below.

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 ratably over the life of the fund based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. AB 1054 did not specify a period of coverage for the Wildfire Fund, and so this accounting treatment is subject to significant accounting judgments and estimates. 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 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 re-evaluate the estimated period of coverage annually and as required when additional information becomes available. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility initially estimated a period of coverage of 15 years. In the first quarter of 2024, the annual assessment resulted in the expected life of the Wildfire Fund increasing to 20 years after incorporating 2023 loss information into the dataset with no new events triggering a claim against the Wildfire Fund. PG&E Corporation and the Utility also assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that claims are made from the Wildfire Fund for catastrophic wildfires.

As of December 31, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $564 million in Other noncurrent liabilities, $301 million in Current assets - Wildfire Fund asset, and $4.1 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2024 and 2023, the Utility recorded amortization and accretion expense of $383 million and $567 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Consolidated Statements of Income.

For more information, see “Wildfire Fund under AB 1054” in Note 14 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 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, “Wildfire-Related Contingencies” in Note 14, and “Other Contingencies and Commitments” in Note 15 below.

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, 2024 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
Beginning balance	$	(28)	$	18	$	2	$	(8)
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively)	—		—		1		1
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively)	(268)		29		—		(239)
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively)	260		(29)		—		231
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(2)		2		—		—
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively) (1)	1		(16)		—		(15)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)	2		14		—		16
Net current period other comprehensive income	(7)		—		1		(6)
Ending balance	$	(35)	$	18	$	3	$	(14)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2023 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		8		8
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively)	(196)		73		—		(123)
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively)	180		(73)		—		107
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(3)		2		—		(1)
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively)(1)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1)	2		12		—		14
Net current period other comprehensive income (loss)	(16)		—		8		(8)
Ending balance	$	(28)	$	18	$	2	$	(8)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 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 it can ascertain an implicit discount rate from the leasing arrangement. 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 as paid in conformity with ratemaking.

Financing Leases

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024 and 2023, the Utility made total fixed cash payments of $315 million and $142 million, respectively, for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Financing leases were immaterial for the year ended December 31, 2022. 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 financing lease ROU assets and lease liabilities relate to the Oakland Headquarters lease discussed below.

Oakland Headquarters Lease and Purchase

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 also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2024, the Landlord has made available approximately 715,000 rentable square feet of the leased premises for the Utility’s use.

On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the legal parcel that contains the Lakeside Building (the “Property”), as modified. Pursuant to the Agreement of Purchase and Sale and Joint Escrow Instructions, the purchase price of the Property will be $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing on or before June 3, 2025. The Utility will also receive a credit of approximately $172 million towards the final payment, subject to adjustments, which represents the estimated outstanding principal balance of a loan carried by the Property that will be assigned to, and assumed by, the Utility at closing. The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing.

The execution of the Amendment to Office Lease Agreement on July 11, 2023 triggered a modification of the Lease, which resulted in the Lease being remeasured and reclassified from an operating lease to a financing lease during the year ended 2023.

As of December 31, 2024, the Utility has recorded $807 million in Financing lease ROU assets, $282 million in accumulated amortization, $136 million in leasehold improvements, net of accumulated amortization, which includes $51 million that was provided to the Utility as lease incentives, and $575 million in current Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended. As of December 31, 2023, the Utility recorded $787 million in Financing lease ROU assets, $108 million in accumulated amortization, $218 million in leasehold improvements, net of accumulated amortization, which includes $134 million that was provided to the Utility as lease incentives, $259 million in current Financing lease liabilities, and $554 million in noncurrent Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended.

At December 31, 2024 and 2023, the Utility’s financing lease had a weighted average remaining lease term of 0.5 years and 1.6 years and a weighted average discount rate of 6.2% and 6.5%, respectively.

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

	Year Ended December 31,
(in millions)	2024		2023
Financing lease fixed cost:
Amortization of ROU assets	$	274	$	115
Interest on lease liabilities	42		27
Financing lease variable cost	9		3
Total financing lease costs	$	325	$	145

At December 31, 2024, the Utility expects to pay $591 million of lease payments in 2025.

Operating Leases

Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024, 2023, and 2022, the Utility made total cash payments, including fixed and variable, of $1.6 billion, $1.9 billion, and $2.3 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. 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 15 below.

At December 31, 2024 and 2023, the Utility’s operating leases had a weighted average remaining lease term of 7.5 years and 8.2 years and a weighted average discount rate of 6.5% and 6.4%, respectively.

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

	Year Ended December 31,
(in millions)	2024		2023		2022
Operating lease fixed cost	$	116	$	269	$	500
Operating lease variable cost	1,524		1,632		1,829
Total operating lease costs	$	1,640	$	1,901	$	2,329

At December 31, 2024, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2024
2025	$	116
2026	112
2027	110
2028	97
2029	62
Thereafter	195
Total lease payments	692
Less imputed interest	(173)
Total	$	519

Recently Adopted Accounting Standards

Segment Reporting

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amended the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. PG&E Corporation and the Utility adopted this ASU in December 2024. See “Segment Reporting” above for additional disclosures as a result of adopting this ASU. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and income taxes paid disaggregated by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. PG&E Corporation and the Utility do not expect the guidance to have a significant impact on their Consolidated Financial Statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

12 Months Ended

Dec. 31, 2024

Regulated Operations [Abstract]

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

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. The Utility does not earn a return on regulatory assets if the related costs do not accrue interest.

Noncurrent regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2024		2023
Pension benefits (1)	$	673	$	348	Indefinitely
Environmental compliance costs	1,172		1,218		32 years
Price risk management	167		160		up to 15.5 years
Catastrophic event memorandum account (2)	742		1,074		Various
Wildfire-related accounts (3)	1,697		2,915		1 - 3 years
Deferred income taxes (4)	4,771		3,543		Various
Financing costs (5)	216		196		Various
SB 901 securitization (6)	5,194		5,249		28 years
General rate case memorandum accounts (7)	95		1,291		Various
Other	834		1,195		Various
Total noncurrent regulatory assets	$	15,561	$	17,189

(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) 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, 2024 and 2023, $1 million and $43 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FHPMA, FRMMA, WMPMA, WMBA, VMBA and MGMA.

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

(5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings.

(6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds 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 5 below.

(7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 relates to revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2024 and 2023, the Utility had current regulatory liabilities of $1.2 billion. At December 31, 2024, current regulatory liabilities consisted primarily of billed revenues exceeding TO20 transmission revenue requirements. Current regulatory liabilities are included within Current liabilities-other in the Consolidated Balance Sheets.

Noncurrent Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2024		2023
Cost of removal obligations (1)	$	8,943	$	8,191
Public purpose programs (2)	1,112		1,238
Employee benefit plans (3)	1,088		1,032
Transmission tower wireless licenses (4)	306		384
SFGO sale (5)	79		185
SB 901 securitization (6)	6,295		6,628
Wildfire self-insurance (7)	804		407
Other	790		1,379
Total noncurrent regulatory liabilities	$	19,417	$	19,444

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

(2) 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.

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

(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. Of the $306 million, $273 million will be refunded to FERC-jurisdictional customers, and $33 million will be refunded to CPUC-jurisdictional customers.

(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.

(6) 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. See Note 5 below.

(7) Represents amounts collected through rates designated for wildfire self-insurance. See Note 14 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 timing differences between when costs are incurred and customer revenues are collected.

Some regulatory balancing accounts receivable earn interest which is reflected in Interest income in the Consolidated Statements of Income. Some regulatory balancing accounts payable accrue interest which is reflected in Interest expense in the Consolidated Statements of Income. Interest income from balancing accounts receivable was $537 million, $547 million and $153 million for the years ended December 31, 2024, 2023, and 2022, respectively. Interest expense from balancing accounts payable was $323 million, $257 million and $81 million for the years ended December 31, 2024, 2023, and 2022, respectively.

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

	Receivable Balance at December 31,
(in millions)	2024		2023
Electric distribution (1)	$	1,591	$	1,092
Electric transmission (2)	117		99
Gas distribution and transmission (3)	387		144
Energy procurement (4)	1,066		1,002
Public purpose programs (5)	162		137
Wildfire-related accounts (6)	979		568
Insurance premium costs (7)	38		227
Residential uncollectibles balancing accounts (8)	260		507
Catastrophic event memorandum account (9)	500		413
General rate case memorandum accounts (10)	1,113		1,097
Other	1,014		374
Total regulatory balancing accounts receivable	$	7,227	$	5,660

	Payable Balance at December 31,
(in millions)	2024		2023
Electric transmission (2)	$	883	$	200
Gas distribution and transmission (3)	72		224
Energy procurement (4)	329		77
Public purpose programs (5)	882		299
SFGO sale	93		79
Wildfire-related accounts (6)	337		125
Nuclear decommissioning adjustment mechanism (11)	23		216
Other	550		449
Total regulatory balancing accounts payable	$	3,169	$	1,669

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

(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases.

(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(4) 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.

(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA.

(7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC.

(8) 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. The RUBA balance decreased from December 31, 2023 to December 31, 2024 mainly due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

(9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, and final decision on the 2023 WMCE interim rate relief.

(10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.

(11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision.

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DEBT

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

DEBT

DEBT

Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2024:

(in millions)	Termination Date		Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2029	(1)	$	4,400	(2)	$	—	$	(633)	$	3,767
Utility Receivables Securitization Program (3)	June 2026		1,500		(4)	—		—		1,500		(4)
PG&E Corporation revolving credit facility	June 2027		500			—		—		500
Total credit facilities			$	6,400		$	—	$	(633)	$	5,767

(1) On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

(2) Includes a $2.0 billion letter of credit sublimit.

(3) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 April 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 26, 2024, the Utility amended its existing Receivables Securitization Program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

On June 28, 2024, the Utility amended its then-existing bridge term loan credit agreement to, among other things, (i) extend the maturity date from August 15, 2024 to December 16, 2024, and (ii) modify the mandatory prepayment provision to require the Utility to prepay term loans outstanding under such credit agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance of debt securities or incurrence of any debt under any bank credit facilities (excluding AB 1054 securitizations and the Utility’s revolving credit agreement). As of December 31, 2024, the bridge term loan was no longer outstanding.

On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

PG&E Corporation

On July 25, 2024, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date from June 22, 2026 to June 22, 2027 (subject to a one-year extension at the option of PG&E Corporation), and (ii) remove the cash coverage ratio covenant.

AB 1054 Securitization

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 16, 2024, CPUC issued a final decision approving a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the second quarter of 2024. In addition, the final decision authorized one or more series of recovery bonds and authorized the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.

On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of senior secured recovery bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $300 million with an interest rate of 4.838% due June 1, 2035, (2) approximately $373 million with an interest rate of 5.231% due June 1, 2042, and (3) approximately $746 million with an interest rate of 5.529% due June 1, 2051. The payment dates for the senior secured recovery bonds are June 1 and December 1 of each year, commencing on June 1, 2025 and continuing until the final repayment date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the senior secured recovery bonds, including (1) the Recovery Property Servicing Agreement (“the Servicing Agreement”), (2) the Recovery Property Purchase and Sale Agreement (the “Sale Agreement”), and (3) the Administration Agreement (the “Administration Agreement”), each dated as of August 1, 2024.

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property created pursuant to the Wildfire Financing Law and the Financing Order (each as defined in the Sale Agreement) 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 Sale Agreement); 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 2 above.

Short-Term Borrowings

On September 5, 2024, the Utility completed the sale of $1.0 billion aggregate principal amount of Floating Rate First Mortgage Bonds due 2025. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

Long-Term Debt Issuances and Redemptions

Utility

On February 28, 2024, the Utility completed the sale of (i) $850 million aggregate principal amount of 5.550% First Mortgage Bonds due 2029, (ii) $1.1 billion aggregate principal amount of 5.800% First Mortgage Bonds due 2034 and (iii) $300 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The Utility used the net proceeds for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On September 5, 2024, the Utility completed the sale of $750 million aggregate principal amount of 5.900% First Mortgage Bonds due 2054. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

PG&E Corporation

On September 11, 2024, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes, including to fully prepay all loans outstanding under its existing term loan agreement in an aggregate principal amount equal to $500 million. During the year ended December 31, 2024, PG&E Corporation recognized a $9 million loss within Interest expense on the Consolidated Statements of Income related to the early extinguishment and associated write-off of deferred debt issuance costs of the term loan agreement.

On November 15, 2024, PG&E Corporation completed the sale of an additional $500 million aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes.

Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% convertible senior secured notes due December 1, 2027 (the “Convertible Notes”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

•during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or

•upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.

On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2024, none of the conditions allowing holders of the Convertible Notes to convert had been met.

The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2024 and 2023, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.13 billion and $2.12 billion, with unamortized debt issuance costs of $20 million and $27 million, respectively, in Long-term debt. For the year ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $98 million and $7 million, respectively.

The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2024		December 31, 2023
PG&E Corporation
Term Loan	7.85%	$	—	$	500
Convertible Notes due 2027	4.25%	2,150		2,150
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Junior Subordinated Notes due 2055	7.38%	1,500		—
Unamortized discount, premium and debt issuance costs, net		(39)		(51)
Total PG&E Corporation Long-Term Debt		5,611		4,599
Utility
First Mortgage Bonds - Stated Maturity:
2024	3.40% - 3.75%	—		800
2025	3.45% - 4.95%	1,925		1,925
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 4.65%	1,975		1,975
2029	4.20% - 6.10%	2,100		1,250
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		1,050
2033	6.15% - 6.40%	1,900		1,900
2034	5.80% - 6.95%	1,900		800
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		550
2053	6.70% - 6.75%	2,300		2,000
2054	5.90%	750		—
Less: current portion, net of unamortized discount and debt issuance costs		(1,924)		(800)
Unamortized discount, premium and debt issuance costs, net		(226)		(246)
Total Utility First Mortgage Bonds		36,927		35,831
Recovery Bonds (1)		10,367		9,124
Less: current portion		(222)		(176)
DWR Loan (2)		886		98
Credit Facilities
Receivables Securitization Program	6.75%	—		1,499
2-Year Term Loan	6.60%	—		400
Less: current portion		—		(400)
Total Utility Long-Term Debt		47,958		46,376
Total PG&E Corporation Consolidated Long-Term Debt		$	53,569	$	50,975

(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2024 are reflected in the table below:

(in millions, except interest rates)	2025			2026			2027			2028			2029			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	4.25		%	5.00		%	—		%	6.53		%	5.39		%
Fixed rate obligations	$	—		$	—		$	2,150		$	1,000		$	—		$	2,500		$	5,650
Utility (1)
Average fixed interest rate	3.82		%	3.10		%	3.22		%	3.58		%	5.52		%	4.72		%	4.44		%
Fixed rate obligations	$	1,925		$	2,551		$	3,000		$	1,975		$	2,100		$	27,526		$	39,077
Recovery Bonds (2)
AB 1054 obligations	$	88		$	81		$	84		$	88		$	91		$	2,728		$	3,160
SB 901 obligations	135			140			146			152			159			6,475			7,207
Total consolidated debt	$	2,148		$	2,772		$	5,380		$	3,215		$	2,350		$	39,229		$	55,094

(1) The balance excludes DWR loan, see Note 2 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 11 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. 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, 2024.

Upon issuance of senior secured 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, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $650 million is required to be contributed no later than March 31, 2025 unless certain conditions are met requiring an earlier contribution or unless otherwise ordered by the CPUC. 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 sold PG&E Corporation common stock shares it held, the SB 901 securitization regulatory liability increased accordingly. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. 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, 2024, the Utility recorded $328 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income. During the year ended December 31, 2023, the Utility recorded SB 901 securitization charges, net, of $1.3 billion for tax benefits realized within Income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and $322 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income.

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:

	SB 901 securitization regulatory asset
(in millions)	2024		2023
Balance at January 1	$	5,249	$	5,378
Amortization	(55)		(129)
Balance at December 31	$	5,194	$	5,249

	SB 901 securitization regulatory liability
(in millions)	2024		2023
Balance at January 1	$	(6,628)	$	(5,800)
Amortization	383		451
Additions(1)	(50)		(1,279)
Balance at December 31	$	(6,295)	$	(6,628)

(1) Includes $16 million and $12 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2024 and 2023, respectively.

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

DEBT

Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2024:

(in millions)	Termination Date		Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2029	(1)	$	4,400	(2)	$	—	$	(633)	$	3,767
Utility Receivables Securitization Program (3)	June 2026		1,500		(4)	—		—		1,500		(4)
PG&E Corporation revolving credit facility	June 2027		500			—		—		500
Total credit facilities			$	6,400		$	—	$	(633)	$	5,767

(1) On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

(2) Includes a $2.0 billion letter of credit sublimit.

(3) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 April 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 26, 2024, the Utility amended its existing Receivables Securitization Program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

On June 28, 2024, the Utility amended its then-existing bridge term loan credit agreement to, among other things, (i) extend the maturity date from August 15, 2024 to December 16, 2024, and (ii) modify the mandatory prepayment provision to require the Utility to prepay term loans outstanding under such credit agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance of debt securities or incurrence of any debt under any bank credit facilities (excluding AB 1054 securitizations and the Utility’s revolving credit agreement). As of December 31, 2024, the bridge term loan was no longer outstanding.

On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

PG&E Corporation

On July 25, 2024, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date from June 22, 2026 to June 22, 2027 (subject to a one-year extension at the option of PG&E Corporation), and (ii) remove the cash coverage ratio covenant.

AB 1054 Securitization

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 16, 2024, CPUC issued a final decision approving a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the second quarter of 2024. In addition, the final decision authorized one or more series of recovery bonds and authorized the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.

On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of senior secured recovery bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $300 million with an interest rate of 4.838% due June 1, 2035, (2) approximately $373 million with an interest rate of 5.231% due June 1, 2042, and (3) approximately $746 million with an interest rate of 5.529% due June 1, 2051. The payment dates for the senior secured recovery bonds are June 1 and December 1 of each year, commencing on June 1, 2025 and continuing until the final repayment date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the senior secured recovery bonds, including (1) the Recovery Property Servicing Agreement (“the Servicing Agreement”), (2) the Recovery Property Purchase and Sale Agreement (the “Sale Agreement”), and (3) the Administration Agreement (the “Administration Agreement”), each dated as of August 1, 2024.

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property created pursuant to the Wildfire Financing Law and the Financing Order (each as defined in the Sale Agreement) 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 Sale Agreement); 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 2 above.

Short-Term Borrowings

On September 5, 2024, the Utility completed the sale of $1.0 billion aggregate principal amount of Floating Rate First Mortgage Bonds due 2025. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

Long-Term Debt Issuances and Redemptions

Utility

On February 28, 2024, the Utility completed the sale of (i) $850 million aggregate principal amount of 5.550% First Mortgage Bonds due 2029, (ii) $1.1 billion aggregate principal amount of 5.800% First Mortgage Bonds due 2034 and (iii) $300 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The Utility used the net proceeds for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On September 5, 2024, the Utility completed the sale of $750 million aggregate principal amount of 5.900% First Mortgage Bonds due 2054. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its then-existing bridge term loan credit agreement.

PG&E Corporation

On September 11, 2024, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes, including to fully prepay all loans outstanding under its existing term loan agreement in an aggregate principal amount equal to $500 million. During the year ended December 31, 2024, PG&E Corporation recognized a $9 million loss within Interest expense on the Consolidated Statements of Income related to the early extinguishment and associated write-off of deferred debt issuance costs of the term loan agreement.

On November 15, 2024, PG&E Corporation completed the sale of an additional $500 million aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes.

Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% convertible senior secured notes due December 1, 2027 (the “Convertible Notes”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

•during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or

•upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.

On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2024, none of the conditions allowing holders of the Convertible Notes to convert had been met.

The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2024 and 2023, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.13 billion and $2.12 billion, with unamortized debt issuance costs of $20 million and $27 million, respectively, in Long-term debt. For the year ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $98 million and $7 million, respectively.

The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt:

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2024		December 31, 2023
PG&E Corporation
Term Loan	7.85%	$	—	$	500
Convertible Notes due 2027	4.25%	2,150		2,150
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Junior Subordinated Notes due 2055	7.38%	1,500		—
Unamortized discount, premium and debt issuance costs, net		(39)		(51)
Total PG&E Corporation Long-Term Debt		5,611		4,599
Utility
First Mortgage Bonds - Stated Maturity:
2024	3.40% - 3.75%	—		800
2025	3.45% - 4.95%	1,925		1,925
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 4.65%	1,975		1,975
2029	4.20% - 6.10%	2,100		1,250
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		1,050
2033	6.15% - 6.40%	1,900		1,900
2034	5.80% - 6.95%	1,900		800
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		550
2053	6.70% - 6.75%	2,300		2,000
2054	5.90%	750		—
Less: current portion, net of unamortized discount and debt issuance costs		(1,924)		(800)
Unamortized discount, premium and debt issuance costs, net		(226)		(246)
Total Utility First Mortgage Bonds		36,927		35,831
Recovery Bonds (1)		10,367		9,124
Less: current portion		(222)		(176)
DWR Loan (2)		886		98
Credit Facilities
Receivables Securitization Program	6.75%	—		1,499
2-Year Term Loan	6.60%	—		400
Less: current portion		—		(400)
Total Utility Long-Term Debt		47,958		46,376
Total PG&E Corporation Consolidated Long-Term Debt		$	53,569	$	50,975

(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2024 are reflected in the table below:

(in millions, except interest rates)	2025			2026			2027			2028			2029			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	4.25		%	5.00		%	—		%	6.53		%	5.39		%
Fixed rate obligations	$	—		$	—		$	2,150		$	1,000		$	—		$	2,500		$	5,650
Utility (1)
Average fixed interest rate	3.82		%	3.10		%	3.22		%	3.58		%	5.52		%	4.72		%	4.44		%
Fixed rate obligations	$	1,925		$	2,551		$	3,000		$	1,975		$	2,100		$	27,526		$	39,077
Recovery Bonds (2)
AB 1054 obligations	$	88		$	81		$	84		$	88		$	91		$	2,728		$	3,160
SB 901 obligations	135			140			146			152			159			6,475			7,207
Total consolidated debt	$	2,148		$	2,772		$	5,380		$	3,215		$	2,350		$	39,229		$	55,094

(1) The balance excludes DWR loan, see Note 2 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 11 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. 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, 2024.

Upon issuance of senior secured 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, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $650 million is required to be contributed no later than March 31, 2025 unless certain conditions are met requiring an earlier contribution or unless otherwise ordered by the CPUC. 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 sold PG&E Corporation common stock shares it held, the SB 901 securitization regulatory liability increased accordingly. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. 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, 2024, the Utility recorded $328 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income. During the year ended December 31, 2023, the Utility recorded SB 901 securitization charges, net, of $1.3 billion for tax benefits realized within Income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and $322 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income.

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:

	SB 901 securitization regulatory asset
(in millions)	2024		2023
Balance at January 1	$	5,249	$	5,378
Amortization	(55)		(129)
Balance at December 31	$	5,194	$	5,249

	SB 901 securitization regulatory liability
(in millions)	2024		2023
Balance at January 1	$	(6,628)	$	(5,800)
Amortization	383		451
Additions(1)	(50)		(1,279)
Balance at December 31	$	(6,295)	$	(6,628)

(1) Includes $16 million and $12 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2024 and 2023, respectively.

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COMMON STOCK AND SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2024

Common Stock And Share-Based Compensation [Abstract]

COMMON STOCK AND SHARE-BASED COMPENSATION

COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 2,193,573,536 shares of common stock outstanding at December 31, 2024. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2024.

On December 4, 2024, PG&E Corporation issued 55,961,070 shares of common stock, no par value, for cash proceeds of approximately $1.13 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.

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 deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate value of the 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.

Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore 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. Accordingly, although PG&E Corporation had 2,671,320,389 common shares outstanding as of February 5, 2025, only 2,193,576,799 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date.

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

CPUC holding company rules require that the Utility’s dividend policy be established by the Utility’s Board of Directors on the same basis as if the Utility were a stand-alone utility company, and that the capital requirements of Utility, as deemed to be necessary to meet the Utility’s electricity service obligations, shall receive first priority from the Boards of Directors of both PG&E Corporation and the Utility. The CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. The CPUC has granted the Utility a temporary waiver from compliance with its authorized capital structure until 2025 for the financing in place upon the Utility’s emergence from Chapter 11.

California law also requires that for a dividend to be declared: (a) retained earnings must equal to or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation’s assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. A California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature.

Additionally, neither PG&E Corporation nor the Utility may pay common stock dividends unless all cumulative preferred dividends on PG&E Corporation’s Mandatory Convertible Preferred Stock and the Utility’s preferred stock, respectively, have been paid.

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 and the Utility’s 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.

Utility

On each of February 13, May 16, and September 19, and November 29, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million, $500 million, $500 million, and $575 million, which were paid to PG&E Corporation on March 25, June 3, September 20, and December 24, 2024, respectively.

PG&E Corporation

On each of February 13, May 16, and September 19, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, each declaration totaling $21 million, which were paid on April 15, July 15, and October 15, 2024, to holders of record as of March 28, June 28 and September 30, 2024, respectively. On November 29, 2024, the Board of Directors of PG&E Corporation declared a new quarterly common stock dividend of $0.025 per share, totaling $55 million, which was paid on January 15, 2025, to holders of record as of December 31, 2024.

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 55,900,800 shares were available for future awards at December 31, 2024.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2024:

(in millions)	2024		2023		2022
Restricted stock units	67		64		60
Performance shares	31		27		55
Total compensation expense (pre-tax)	$	98	$	91	$	115
Total compensation expense (after-tax)	$	71	$	65	$	83

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, 2024, 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 2024 or 2023.

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, 2024.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2024:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1	1,396,261	$	8.2
Granted (1)	—	—
Exercised	—	—
Forfeited or expired	(652,298)	6.89
Outstanding at December 31	743,963	10.23		2.58
Vested or expected to vest at December 31	743,963	10.23		2.58
Exercisable at December 31	743,963	$	10.23	2.58

(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 2024, 2023, and 2022 was $16.74, $15.70, and $11.40, respectively.  The total fair value of restricted stock units that vested during 2024, 2023, and 2022 was $62 million, $64 million, and $46 million, respectively.  The tax benefit from restricted stock units that vested in 2024 was $21 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, 2024, $90 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.52 years.

The following table summarizes restricted stock unit activity for 2024:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	9,268,425	$	13.29
Granted	5,273,850	16.74
Vested	(4,922,000)	12.62
Forfeited	(196,693)	15.27
Nonvested at December 31	9,423,582	$	15.52

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 awards based on internal metrics.  The weighted average grant-date fair value for performance shares granted during 2024, 2023, and 2022 was $16.94, $13.39, and $13.44 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, 2024, $48 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.17 years.

The following table summarizes activity for performance shares in 2024:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	6,602,292	$	14.06
Granted	2,714,196	16.94
Vested	(1,779,695)	10.70
Forfeited	(356,587)	13.07
Nonvested at December 31	7,180,206	$	15.52

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PREFERRED STOCK

12 Months Ended

Dec. 31, 2024

Preferred Stock [Abstract]

PREFERRED STOCK

PREFERRED STOCK

PG&E Corporation

PG&E Corporation has authorized 400 million shares of preferred stock.

On December 5, 2024, PG&E Corporation issued 32,200,000 shares of 6.000% Series A Mandatory Convertible Preferred Stock, at $50.00 per share, for cash proceeds of approximately $1.6 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.

Each share of the Mandatory Convertible Preferred Stock will automatically convert on December 1, 2027. The number of shares of common stock issuable on conversion of Mandatory Convertible Preferred Stock will not be more than 2.4331 shares of common stock and not less than 1.9465 shares of common stock.

Other than during a Fundamental Change Conversion Period (as defined in the PG&E Corporation Preferred Stock Certificate of Designation), at any time prior to December 1, 2027, holders of Mandatory Convertible Preferred Stock have the option to elect to convert their shares of the Mandatory Convertible Preferred Stock, in whole or in part (but in no event in increments of less than one share of the Mandatory Convertible Preferred Stock), into shares of common stock at the Minimum Conversion Rate of 1.9465 shares of common stock per share of Mandatory Convertible Preferred Stock, subject to adjustment as described in the Preferred Stock Preliminary Prospectus Supplement.

Dividends on the Mandatory Convertible Preferred Stock are cumulative. All shares of the Mandatory Convertible Preferred Stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of the Mandatory Convertible Preferred Stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The expected dividend payable on the first dividend payment date is approximately $0.7167 per share of the Mandatory Convertible Preferred Stock. Each subsequent dividend is expected to be $0.75 per share of the Mandatory Convertible Preferred Stock. The dividends will be declared on the February 15, May 15, August 15 and November 15 immediately preceding the relevant dividend payment date.

The Mandatory Convertible Preferred Stock ranks senior to PG&E Corporation’s common stock with respect to the payment of dividends. Accordingly, unless accumulated dividends have been paid on all of the Mandatory Convertible Preferred Stock through the most recently completed dividend period, no dividends may be declared or paid on PG&E Corporation’s common stock and PG&E Corporation will not be permitted to repurchase any of its common stock, subject to limited exceptions.

On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share for the period from and including December 5, 2024 to and excluding March 1, 2025, to be payable on March 1, 2025, to holders of record as of February 14, 2025.

Utility

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, 2024 and 2023, 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.

At December 31, 2024, 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, 2024, annual dividends on the Utility’s redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  The Utility paid $14 million of dividends on preferred stock in 2024. The Utility paid approximately $70 million of dividends on preferred stock in 2022, of which approximately $59 million was paid in arrears. On each of February 13, May 16, and September 19, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on May 15, August 15, and November 15, 2024, respectively, to holders of record as of April 30, July 31, and October 31, 2024. On November 29, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on February 15, 2025, to holders of record as of January 31, 2025.

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2024

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 2024, 2023, and 2022.

	Year Ended December 31,
(in millions, except per share amounts)	2024		2023		2022
Income (loss) available for common shareholders	$	2,475	$	2,242	$	1,800
Weighted average common shares outstanding, basic (1)	2,141		2,064		1,987
Add incremental shares from assumed conversions:
Employee share-based compensation	6		6		8
Equity Units	—		68		137
Weighted average common shares outstanding, diluted	2,147		2,138		2,132
Total earnings (loss) per common share, diluted	$	1.15	$	1.05	$	0.84

(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant number of options and securities that were antidilutive. For the year ended December 31, 2024, the calculation of outstanding common shares on a diluted basis excluded the impacts of the Mandatory Convertible Preferred Stock (see Note 7 above), which were antidilutive. In addition, as a result of an irrevocable election made on December 8, 2023 to fix the settlement method to combination settlement, the Convertible Notes (as defined in Note 4) did not have a material impact on the calculation of diluted EPS.

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INCOME TAXES

12 Months Ended

Dec. 31, 2024

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 deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the 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 benefit by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2024		2023		2022		2024		2023		2022
Current:
Federal	$	2	$	(1)	$	(1)	$	2	$	(1)	$	(1)
State	(78)		—		—		(78)		—		—
Deferred:
Federal	(137)		(1,047)		(943)		(72)		(981)		(852)
State	15		(507)		(389)		45		(477)		(348)
Tax credits	(2)		(2)		(5)		(2)		(2)		(5)
Income tax benefit	$	(200)	$	(1,557)	$	(1,338)	$	(105)	$	(1,461)	$	(1,206)

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2024		2023		2024		2023
Deferred income tax assets:
Tax carryforwards	$	9,429	$	9,132	$	8,955	$	8,740
Compensation	171		145		86		82
GHG allowance	471		361		471		361
Wildfire-related claims (1)	295		1,069		295		1,069
Operating lease liability	78		142		78		142
Transmission tower wireless licenses	251		250		251		250
Bad debt	127		134		127		134
Other (2)	140		130		137		109
Total deferred income tax assets	$	10,962	$	11,363	$	10,400	$	10,887
Deferred income tax liabilities:
Property-related basis differences	11,021		10,058		11,009		10,047
Regulatory balancing accounts	878		1,433		878		1,433
Debt financing costs	390		428		390		428
Operating lease ROU asset	78		142		78		142
Income tax regulatory asset (3)	1,335		991		1,335		991
Environmental reserve	248		200		248		200
Other (4)	94		91		94		82
Total deferred income tax liabilities	$	14,044	$	13,343	$	14,032	$	13,323
Total net deferred income tax liabilities	$	3,082	$	1,980	$	3,632	$	2,436

(1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in 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 TCJA.

(4) Amounts primarily include property taxes and prepaid expense.

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,
	2024		2023		2022		2024		2023		2022
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)	(2.0)		(57.9)		(75.8)		(0.8)		(34.4)		(26.9)
Effect of regulatory treatment of fixed asset differences (2)	(28.3)		(63.4)		(123.8)		(24.7)		(40.1)		(49.2)
Tax credits	(0.7)		(2.2)		(3.2)		(0.7)		(2.2)		(1.3)
Fire Victim Trust (3)	—		(126.9)		(160.9)		—		(80.2)		(64.0)
Other, net (4)	1.2		2.2		12.9		1.2		1.1		2.2
Effective tax rate	(8.8)	%	(227.2)	%	(329.8)	%	(4.0)	%	(134.8)	%	(118.2)	%

(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 2024, 2023, and 2022, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA passed in December 2017. In addition, for the 2024 tax year, PG&E Corporation and the Utility will implement the accounting method change related to gas repairs in accordance with Revenue Procedure 2013-15.

(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023 and 2022 and a deferred tax asset write-off associated with the grantor trust election for the Fire Victim Trust in 2021.

(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)	2024		2023		2022		2024		2023		2022
Balance at beginning of year	$	616	$	570	$	498	$	616	$	570	$	498
Additions for tax position taken during a prior year	—		1		—		—		1		—
Reductions for tax position taken during a prior year	(257)		—		(1)		(257)		—		(1)
Additions for tax position taken during the current year	95		45		73		95		45		73
Settlements	—		—		—		—		—		—
Balance at end of year	$	454	$	616	$	570	$	454	$	616	$	570

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2024 for PG&E Corporation and the Utility was $106 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, 2024, 2023, and 2022, these amounts were immaterial.

Tax Audits

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The IRS is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. On June 4, 2024, the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. As a result, in the year ended December 31, 2024, PG&E Corporation determined that it is no longer more likely than not that its deduction related to a portion of the customer bill credits would ultimately be sustained. Accordingly, PG&E Corporation has decreased its Income tax benefit by $70 million in the year ended December 31, 2024 related to state and federal income taxes. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Carryforwards

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

(in millions)	December 31, 2024		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,369	2031 - 2036
Net operating loss carryforward - Post-2017	30,288		N/A
Tax credit carryforward	125		2029 - 2041
State:
Net operating loss carryforward	$	34,901	2039 - 2041
Tax credit carryforward	146		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.

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DERIVATIVES

12 Months Ended

Dec. 31, 2024

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, 2024	December 31, 2023
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	179,257,247	196,063,296
	Options	37,717,500	30,695,000
Electricity (MWh)	Forwards, futures, and swaps	8,576,078	9,169,967
	Options	1,663,200	92,400
	Congestion Revenue Rights (3)	123,040,895	170,465,674

(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, 2024, 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	$	186	$	(16)	$	—	$	170
Noncurrent assets – other	233		—		—		233
Current liabilities – other	(152)		16		—		(136)
Noncurrent liabilities – other	(167)		—		—		(167)
Total commodity risk	$	100	$	—	$	—	$	100

As of December 31, 2023, 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	$	134	$	(8)	$	50	$	176
Other noncurrent assets – other	280		—		—		280
Current liabilities – other	(172)		8		46		(118)
Noncurrent liabilities – other	(160)		—		—		(160)
Total commodity risk	$	82	$	—	$	96	$	178

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 derivative 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, 2024, 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, 2024

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, 2024
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	826	$	—	$	—	$	—	$	826
Pacific Energy Risk Solutions, LLC
Short-term investments	905		—		—		—		905
Total Pacific Energy Risk Solutions, LLC	905		—		—		—		905
Nuclear decommissioning trusts
Short-term investments	53		—		—		—		53
Global equity securities	2,228		—		—		—		2,228
Fixed-income securities	1,250		1,027		—		—		2,277
Assets measured at NAV	—		—		—		—		22
Total nuclear decommissioning trusts (2)	3,531		1,027		—		—		4,580
Customer credit trust
Short-term investments	1		—		—		—		1
Global equity securities	186		—		—		—		186
Fixed-income securities	46		144		—		—		190
Total customer credit trust	233		144		—		—		377
Price risk management instruments (Note 10)
Electricity	—		26		383		(6)		403
Gas	—		10		—		(10)		—
Total price risk management instruments	—		36		383		(16)		403
Rabbi trusts
Short-term investments	107		—		—		—		107
Global equity securities	6		—		—		—		6
Life insurance contracts	—		66		—		—		66
Total rabbi trusts	113		66		—		—		179
Long-term disability trust
Short-term investments	4		—		—		—		4
Assets measured at NAV	—		—		—		—		130
Total long-term disability trust	4		—		—		—		134
TOTAL ASSETS	$	5,612	$	1,273	$	383	$	(16)	$	7,404
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	37	$	248	$	(6)	$	279
Gas	—		34		—		(10)		24
TOTAL LIABILITIES	$	—	$	71	$	248	$	(16)	$	303

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

(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	203	$	—	$	—	$	—	$	203
Nuclear decommissioning trusts
Short-term investments	52		—		—		—		52
Global equity securities	2,144		—		—		—		2,144
Fixed-income securities	1,168		909		—		—		2,077
Assets measured at NAV	—		—		—		—		18
Total nuclear decommissioning trusts (2)	3,364		909		—		—		4,291
Customer credit trust
Short-term investments	49		—		—		—		49
Global equity securities	71		—		—		—		71
Fixed-income securities	29		84		—		—		113
Total customer credit trust	149		84		—		—		233
Price risk management instruments (Note 10)
Electricity	—		7		404		(1)		410
Gas	—		3		—		43		46
Total price risk management instruments	—		10		404		42		456
Rabbi trusts
Short-term investments	102		—		—		—		102
Global equity securities	5		—		—		—		5
Life insurance contracts	—		65		—		—		65
Total rabbi trusts	107		65		—		—		172
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		139
Total long-term disability trust	7		—		—		—		146
TOTAL ASSETS	$	3,830	$	1,068	$	404	$	42	$	5,501
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	43	$	213	$	(6)	$	250
Gas	—		76		—		(48)		28
TOTAL LIABILITIES	$	—	$	119	$	213	$	(54)	$	278

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

(2) Represents amount before deducting $717 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, 2024 or 2023.

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.

Pacific Energy Risk Solutions, LLC

Investments held in Pacific Energy Risk Solutions, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.

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 10 above.

	Fair Value
(in millions)	At December 31, 2024				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	366	$	121	Market approach	CRR auction prices	$ (951) - 50,044 / 2
Power purchase agreements	$	17	$	127	Discounted cash flow	Forward prices	$ 0 - 126 / 47

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

	Fair Value
(in millions)	At December 31, 2023				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	357	$	134	Market approach	CRR auction prices	$ (924) - 16,697 / 1
Power purchase agreements	$	47	$	79	Discounted cash flow	Forward prices	$ 1 - 190 / 60

(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, 2024 and 2023, respectively:

	Price Risk Management Instruments
(in millions)	2024		2023
Asset balance as of January 1	$	191	$	199
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(64)		(8)
Asset balance as of December 31	$	127	$	191

(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, 2024 and December 31, 2023, 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, 2024				At December 31, 2023
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	5,358	$	5,829	$	4,548	$	4,695
Utility	37,812		34,532		35,909		32,866

(1) As of December 31, 2024, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.

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, 2024
Nuclear decommissioning trusts
Short-term investments	$	54	$	—	$	(1)	$	53
Global equity securities	353		1,907		(10)		2,250
Fixed-income securities	2,341		20		(84)		2,277
Total (1)	$	2,748	$	1,927	$	(95)	$	4,580
As of December 31, 2023
Nuclear decommissioning trusts
Short-term investments	$	52	$	—	$	—	$	52
Global equity securities	381		1,792		(11)		2,162
Fixed-income securities	2,103		60		(86)		2,077
Total (1)	$	2,536	$	1,852	$	(97)	$	4,291

(1) Represents amounts before deducting $747 million and $717 million as of December 31, 2024 and December 31, 2023, 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, 2024
Less than 1 year	$	35
1–5 years	742
5–10 years	517
More than 10 years	983
Total maturities of fixed-income securities	$	2,277

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

(in millions)	2024		2023		2022
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	1,980	$	2,235	$	3,316
Gross realized gains on securities	255		80		2
Gross realized losses on securities	(63)		(74)		(3)

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, 2024
Customer credit trust
Short-term investments	$	1	$	—	$	—	$	1
Global equity securities	161		28		(3)		186
Fixed-income securities	193		1		(4)		190
Total	$	355	$	29	$	(7)	$	377
As of December 31, 2023
Customer credit trust
Short-term investments	$	49	$	—	$	—	$	49
Global equity securities	56		16		(1)		71
Fixed-income securities	111		2		—		113
Total	$	216	$	18	$	(1)	$	233

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

	As of
(in millions)	December 31, 2024
Less than 1 year	$	—
1–5 years	44
5–10 years	36
More than 10 years	110
Total maturities of fixed-income securities	$	190

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

(in millions)	2024		2023		2022
Proceeds from sales and maturities of customer credit trust investments	$	398	$	556	$	250
Gross realized gains on securities	10		23		10
Gross realized losses on securities (1)	(8)		(19)		(41)

(1) Includes $0 million and $4 million of impaired debt securities which were written down to their respective fair values during the years ended December 31, 2024 and 2023, respectively.

XML

EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2024

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 2024 and 2023:

Pension Plan

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	17,211	$	16,369
Actual return on plan assets	218		1,518
Company contributions	337		336
Benefits and expenses paid	(999)		(1,012)
Fair value of plan assets at end of year	$	16,767	$	17,211
Change in benefit obligation:
Benefit obligation at beginning of year	$	17,697	$	16,608
Service cost for benefits earned	396		379
Interest cost	916		913
Actuarial loss (gain) (1)	(424)		809
Benefits and expenses paid	(1,000)		(1,012)
Benefit obligation at end of year (2)	$	17,585	$	17,697
Funded Status:
Current liability	$	(10)	$	(9)
Noncurrent liability	(808)		(477)
Net liability at end of year	$	(818)	$	(486)

(1) The actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions; the actuarial loss for the year ended December 31, 2023 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.3 billion at December 31, 2024 and 2023, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,499	$	2,336
Actual return on plan assets	74		260
Company contributions	5		5
Plan participant contribution	84		81
Benefits and expenses paid	(191)		(183)
Fair value of plan assets at end of year	$	2,471	$	2,499
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,377	$	1,339
Service cost for benefits earned	41		38
Interest cost	71		73
Actuarial loss (gain) (1)	(123)		8
Benefits and expenses paid	(174)		(165)
Federal subsidy on benefits paid	3		3
Plan participant contributions	84		81
Benefit obligation at end of year	$	1,279	$	1,377
Funded Status: (2)
Noncurrent asset	$	1,192	$	1,122
Noncurrent liability	—		—
Net asset at end of year	$	1,192	$	1,122

(1) The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets. The actuarial loss for the year ended December 31, 2023 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations, offset by favorable changes in claims cost and demographic assumptions.

(2) At December 31, 2024 and 2023, 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 $261 million and $296 million as of December 31, 2024, and $275 million and $292 million as of December 31, 2023, respectively.

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 Plan” below.  Post-retirement medical and life insurance plans are included in “Postretirement Benefits Other than Pensions” below.

Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan

(in millions)	2024		2023		2022
Service cost for benefits earned (1)	$	396	$	379	$	575
Interest cost	916		913		692
Expected return on plan assets	(1,014)		(981)		(1,189)
Amortization of prior service cost	(3)		(4)		(4)
Amortization of net actuarial loss	1		1		2
Net periodic benefit cost	296		308		76
Less: transfer to regulatory account (2)	39		25		254
Total expense recognized	$	335	$	333	$	330

(1) A portion of service costs are capitalized pursuant to ASC 715.

(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)	2024		2023		2022
Service cost for benefits earned (1)	$	41	$	38	$	62
Interest cost	71		73		53
Expected return on plan assets	(139)		(132)		(130)
Amortization of prior service cost	3		3		7
Amortization of net actuarial gain	(23)		(19)		(40)
Special termination benefits	—		—		22
Net periodic benefit cost	$	(47)	$	(37)	$	(26)

(1) A portion of service costs are capitalized pursuant to ASC 715.

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,
	2024		2023		2022		2024	2023	2022
Discount rate	5.76	%	5.21	%	5.54	%	5.71 - 5.76%	5.18 - 5.22%	5.50 - 5.54%
Rate of future compensation increases	4.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.40	%	6.00	%	6.10	%	3.90 - 7.20%	3.70 - 7.00%	3.70 - 7.30%
Interest crediting rate for cash balance plan	4.41	%	3.86	%	4.19	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2024 was 7.50%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2033 and beyond.

Expected rates of return on plan assets were developed by estimating future asset class 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 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 6.4% compares to a ten-year actual return of 5.1%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 858 Aa-grade non-callable bonds at December 31, 2024.  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
	2025		2024		2023		2025		2024		2023
Global equity securities	26	%	26	%	26	%	30	%	29	%	28	%
Absolute return	1	%	1	%	1	%	—	%	—	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	3	%
Fixed-income securities	65	%	65	%	65	%	67	%	68	%	68	%
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, 2024 and 2023.

	Fair Value Measurements
	At December 31,
	2024								2023
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	126	$	47	$	—	$	173	$	565	$	86	$	—	$	651
Global equity securities	1,310		—		—		1,310		1,270		—		—		1,270
Real assets	437		—		—		437		472		—		—		472
Fixed-income securities	2,180		6,367		16		8,563		1,926		6,802		13		8,741
Assets measured at NAV	—		—		—		6,284		—		—		—		6,080
Total	$	4,053	$	6,414	$	16	$	16,767	$	4,233	$	6,888	$	13	$	17,214
PBOP Plans:
Short-term investments	$	27	$	—	$	—	$	27	$	30	$	—	$	—	$	30
Global equity securities	60		—		—		60		66		—		—		66
Real assets	20		—		—		20		32		—		—		32
Fixed-income securities	431		751		1		1,183		422		795		1		1,218
Assets measured at NAV	—		—		—		1,181		—		—		—		1,160
Total	$	538	$	751	$	1	$	2,471	$	550	$	795	$	1	$	2,506
Total plan assets at fair value							$	19,238							$	19,720

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of zero and $10 million at December 31, 2024 and 2023, 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, 2024 or 2023.

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, 2024 and 2023:

(in millions)
For the year ended December 31, 2024	Fixed-Income
Balance at beginning of year	$	13
Actual return on plan assets:
Relating to assets still held at the reporting date	9
Relating to assets sold during the period	(9)
Purchases, issuances, sales, and settlements:
Purchases	14
Settlements	(11)
Balance at end of year	$	16
(in millions)
For the year ended December 31, 2023	Fixed-Income
Balance at beginning of year	$	8
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(1)
Purchases, issuances, sales, and settlements:
Purchases	10
Settlements	(6)
Balance at end of year	$	13

There were no material transfers out of Level 3 in 2024 or 2023.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $337 million to the pension benefit plans, $31 million to the long-term disability trusts, and $5 million to the other postretirement benefit plans in 2024.  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. The Utility’s pension benefits met all funding requirements under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2025. PG&E Corporation and the Utility plan to contribute $31 million to the long-term disability trusts in 2025, as authorized in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2024, 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
2025	969	81	(1)
2026	1,055	84	(1)
2027	1,083	87	(2)
2028	1,109	89	(2)
2029	1,133	91	(2)
2030-2034	5,997	473	(11)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and 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 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 $175 million, $158 million, and $144 million in 2024, 2023, and 2022, respectively. PG&E Corporation’s default matching contributions under its 401(k) plan are in cash.

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, 2024

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)	2024		2023		2022
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	66	$	80	$	104
Utility employee benefit due to PG&E Corporation	81		74		85

At December 31, 2024 and 2023, the Utility had receivables of $25 million and $26 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 $11 million and $24 million, respectively, to PG&E Corporation included in Accounts payable – other on the Utility’s Consolidated Balance Sheets.

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WILDFIRE-RELATED CONTINGENCIES

12 Months Ended

Dec. 31, 2024

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. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that 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. 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 or the upper end of the range because, as described below, 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.

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. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel 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 complaints, except that the applicable statutes of limitations have run for the 2019 Kincade and 2021 Dixie fires. 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 power 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.

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.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through December 31, 2024.

Payments (in millions)
2019 Kincade Fire	$	958
2021 Dixie Fire	1,359
2022 Mosquito Fire	18
Total at December 31, 2024	$	2,335

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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 133 complaints on behalf of at least 2,960 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. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024 the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation. The court scheduled a trial on their claims for August 4, 2025. The parties have reached settlements in principle for these claims and expect that the trial date will be vacated.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), extending their time to file a complaint.

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 $1.125 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $100 million, of which $75 million was recorded in the third quarter and $25 million was recorded in the fourth quarter, for an aggregate liability of $1.225 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.225 billion do not include, among other things: (i) any punitive damages, (ii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, or (iii) 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 losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	458
Accrued Losses	100
Payments	(291)
Balance at December 31, 2024	$	267

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million, which was fully collected as of December 31, 2023.

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, through its ongoing investigation, 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” below.) 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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 182 complaints on behalf of at least 8,681 individual plaintiffs related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. The court had previously scheduled two trial dates for October 14, 2024 and February 24, 2025. The court has vacated both of those dates and set a new bellwether trial date for June 23, 2025.

The Collins Pine Company and a group of timber companies filed a complaint against PG&E Corporation and the Utility on April 10, 2024. PG&E Corporation and the Utility answered this complaint on May 28, 2024.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer to portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer.

On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

PG&E Corporation and the Utility are aware of a separate putative class complaint. On August 23, 2024, PG&E Corporation and the Utility demurred to the putative class complaint. On January 13, 2025, the court issued an order pursuant to which plaintiff has 30 days to amend the complaint or the case will be abated.

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 $1.6 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $325 million, of which $275 million was recorded in the third quarter and $50 million was recorded in the fourth quarter, for an aggregate liability of $1.925 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.925 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 Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring 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 other than Cal Fire 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 parks 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 losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	870
Accrued Losses	325
Payments	(628)
Balance at December 31, 2024	$	567

As of December 31, 2024, the Utility recorded an insurance receivable of $527 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $925 million for probable recoveries in connection with the 2021 Dixie fire, of which it had received $169 million as of December 31, 2024. 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. As of December 31, 2024, the Utility also recorded a $94 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 $508 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.

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, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) 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, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. 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 ongoing.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 25 complaints on behalf of at least 2,738 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency (“PCWA”), a complaint on behalf of the Middle Fork Project Finance Authority, and complaints on behalf of six public entities. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. On April 24, 2024, PG&E Corporation and the Utility filed cross-complaints against PCWA, alleging that conduct by PCWA was a substantial cause of the 2022 Mosquito fire. The cross-complaints seek property damages, indemnification, attorneys’ fees, and other damages. On January 28, 2025, the court entered an order setting the first individual claimant bellwether trial for November 7, 2025.

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. 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 a liability in the aggregate amount of $100 million as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of December 31, 2024.

PG&E Corporation’s and the Utility’s accrued estimated losses 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, or (iv) any other amounts that are not reasonably estimable.

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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	85
Accrued Losses	—
Payments	(3)
Balance at December 31, 2024	$	82

As of December 31, 2024, the Utility recorded an insurance receivable of $90 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of December 31, 2024, the Utility also recorded a $7 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 $53 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, through rates, and from 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,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2024 are:

Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	527	$	90
FERC TO rates	94		7
WEMA	508		53
Wildfire Fund	925		—
Probable recoveries at December 31, 2024 (1)	$	2,054	$	150

(1) Includes legal costs of $123 million and $50 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2024.

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

Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.

Insurance Receivable

As of December 31, 2024, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $527 million and $90 million in connection with 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. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2023:

Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2023	$	326	$	63	$	389
Accrued insurance recoveries	1		27		28
Reimbursements	(300)		—		(300)
Balance at December 31, 2024	$	27	$	90	$	117

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 reasonableness 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, 2024, the Utility recorded reductions of $94 million and $7 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, 2024, 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 $508 million and $53 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund under AB 1054

On July 12, 2019, AB 1054 became law. The law 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 arising from wildfires 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, 2024 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. This reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the IOU’s electric transmission and distribution rate base in the year of the prudency determination. A utility would not be required to reimburse the Wildfire Fund for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Utility, the disallowance cap would be approximately $4.1 billion for 2024. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2024 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. 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 11, 2024, the OEIS approved the Utility’s 2024 application and issued the Utility’s 2024 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts in the fund are exhausted. The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable 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 the participating 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 PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, 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. AB 1054 authorizes the reimbursement of funds where a participating utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

As of December 31, 2024, PG&E Corporation and the Utility recorded $600 million and $156 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2023:

Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2023	$	600
Accrued Wildfire Fund recoveries	325
Claims paid by Wildfire Fund	(169)
Balance at December 31, 2024	$	756

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” 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, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, 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 due to the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, 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 settlement.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its 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.

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 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 of 1933, as amended, 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 former officers and directors, and the underwriters. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation.

On August 21, 2024, the District Court entered an order setting a briefing schedule for renewed motions to dismiss the third amended complaint. Opening briefs were filed on October 24, 2024, opposition briefs were filed December 20, 2024, and reply briefs were filed January 31, 2025.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and proceeds from any insurance 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. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities 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. Such claims could 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 January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing 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.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with 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 continue to prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations

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.

PG&E Corporation and the Utility additionally may have 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 March 28, 2025.

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 assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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

Rates under the TO rate case for 2017 (“TO18”) were in effect from March 1, 2017 through February 28, 2018. Rates under the TO rate case for 2018 (“TO19”) were in effect from March 1, 2018 through April 30, 2019. Rates under the TO rate case for 2019 (“TO20”) were in effect from May 1, 2019 through December 31, 2023. The FERC previously approved settlement agreements for TO19 and TO20 resolving most issues.

On May 31, 2024, the Utility submitted a settlement to the FERC resolving all outstanding issues in the TO18, TO19, and TO20 rate cases. On August 22, 2024, the FERC approved the settlement. As a result, the Utility will refund $236 million, $358 million, and $405 million (plus applicable interest) to retail customers for TO18, TO19, and TO20, respectively. Approval of the settlement did not have a material impact on the Utility’s financial statements in the year ended December 31, 2024. The refunds will occur over 12 months, effective January 1, 2025. The settlement provided that the Utility may seek authorization from the CPUC through a memorandum account to recover up to $473 million through CPUC jurisdictional rates of the general, common and intangible plant cost that had been allocated to FERC-jurisdictional rates in TO18, TO19, and TO20.

2022 WMCE Interim Rate Relief Subject to Refund

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 the implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

2023 WMCE Interim Rate Relief Subject to Refund

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 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 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

On September 16, 2024, the CPUC issued a final decision on interim rate that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

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 $74 million and $89 million as of December 31, 2024 and December 31, 2023, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.

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 Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2024		December 31, 2023
Topock natural gas compressor station	$	294	$	276
Hinkley natural gas compressor station	97		104
Former MGP sites owned by the Utility or third parties (1)	782		809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	76		107
Fossil fuel-fired generation facilities and sites (3)	18		19
Total environmental remediation liability	$	1,267	$	1,315

(1) Primarily driven by the following sites: San Francisco Beach Street, 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 EPA 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, 2024, 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, 2024, the Utility expected to recover $1.1 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. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $211 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’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 action to meet interim cleanup targets. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $123 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. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $637 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. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 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. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $16 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 European Mutual Association for Nuclear Insurance (“EMANI”), covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

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 DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident (including terrorism and cybersecurity) and $2.5 billion per non-nuclear incident for DCPP. For Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. These coverage amounts are shared by all NEIL members. EMANI shares losses with NEIL as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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 $42 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $500 million for DCPP. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 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 $500 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, 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, 2024:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Natural Gas		Other (1)		Total
2025	$	2,010	$	910	$	443	$	354	$	3,717
2026	1,952		866		348		162		3,328
2027	1,896		800		190		284		3,170
2028	1,875		800		103		141		2,919
2029	1,831		716		92		43		2,682
Thereafter	14,229		2,730		41		5		17,005
Total purchase commitments	$	23,793	$	6,822	$	1,217	$	989	$	32,821

(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, qualifying facilities (“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 2025 and 2045.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement 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 2025 and 2044.

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, 2024, QF contracts in operation expire at various dates between 2025 and 2042.  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 $2.1 billion in 2024, $2.4 billion in 2023, and $2.8 billion in 2022.

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 along with a facility associated with a third party tolling agreement.  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 2025 and 2042.  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 $0.8 billion in 2024, $2.5 billion in 2023, and $2.4 billion in 2022.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2025 and 2030 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 $294 million in 2024, $180 million in 2023, and $44 million in 2022.

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 2025 and 2058, as well as other multi-year agreements.  At December 31, 2024, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2025	$	84
2026	44
2027	47
2028	37
2029	34
Thereafter	333
Total minimum payments	$	579

Payments for other commitments were $105 million in 2024, $106 million in 2023, and $63 million in 2022.  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 $650 million is to be made in 2025. If the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution of up to $775 million in 2040. The Utility also will share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

Additionally, the Utility agreed to purchase the Lakeside Building for $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. See “Oakland Headquarters Lease and Purchase” in Note 2 above.

XML

OTHER CONTINGENCIES AND COMMITMENTS

12 Months Ended

Dec. 31, 2024

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. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that 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. 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 or the upper end of the range because, as described below, 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.

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. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel 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 complaints, except that the applicable statutes of limitations have run for the 2019 Kincade and 2021 Dixie fires. 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 power 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.

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.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through December 31, 2024.

Payments (in millions)
2019 Kincade Fire	$	958
2021 Dixie Fire	1,359
2022 Mosquito Fire	18
Total at December 31, 2024	$	2,335

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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 133 complaints on behalf of at least 2,960 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. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024 the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation. The court scheduled a trial on their claims for August 4, 2025. The parties have reached settlements in principle for these claims and expect that the trial date will be vacated.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), extending their time to file a complaint.

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 $1.125 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $100 million, of which $75 million was recorded in the third quarter and $25 million was recorded in the fourth quarter, for an aggregate liability of $1.225 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.225 billion do not include, among other things: (i) any punitive damages, (ii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, or (iii) 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 losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	458
Accrued Losses	100
Payments	(291)
Balance at December 31, 2024	$	267

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million, which was fully collected as of December 31, 2023.

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, through its ongoing investigation, 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” below.) 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.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 182 complaints on behalf of at least 8,681 individual plaintiffs related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. The court had previously scheduled two trial dates for October 14, 2024 and February 24, 2025. The court has vacated both of those dates and set a new bellwether trial date for June 23, 2025.

The Collins Pine Company and a group of timber companies filed a complaint against PG&E Corporation and the Utility on April 10, 2024. PG&E Corporation and the Utility answered this complaint on May 28, 2024.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer to portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer.

On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

PG&E Corporation and the Utility are aware of a separate putative class complaint. On August 23, 2024, PG&E Corporation and the Utility demurred to the putative class complaint. On January 13, 2025, the court issued an order pursuant to which plaintiff has 30 days to amend the complaint or the case will be abated.

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 $1.6 billion as of December 31, 2023 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2024 of $325 million, of which $275 million was recorded in the third quarter and $50 million was recorded in the fourth quarter, for an aggregate liability of $1.925 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.925 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 Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring 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 other than Cal Fire 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 parks 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 losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	870
Accrued Losses	325
Payments	(628)
Balance at December 31, 2024	$	567

As of December 31, 2024, the Utility recorded an insurance receivable of $527 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $925 million for probable recoveries in connection with the 2021 Dixie fire, of which it had received $169 million as of December 31, 2024. 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. As of December 31, 2024, the Utility also recorded a $94 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 $508 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.

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, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) 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, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. 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 ongoing.

As of February 5, 2025, PG&E Corporation and the Utility are aware of approximately 25 complaints on behalf of at least 2,738 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency (“PCWA”), a complaint on behalf of the Middle Fork Project Finance Authority, and complaints on behalf of six public entities. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. On April 24, 2024, PG&E Corporation and the Utility filed cross-complaints against PCWA, alleging that conduct by PCWA was a substantial cause of the 2022 Mosquito fire. The cross-complaints seek property damages, indemnification, attorneys’ fees, and other damages. On January 28, 2025, the court entered an order setting the first individual claimant bellwether trial for November 7, 2025.

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. 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 a liability in the aggregate amount of $100 million as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of December 31, 2024.

PG&E Corporation’s and the Utility’s accrued estimated losses 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, or (iv) any other amounts that are not reasonably estimable.

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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	85
Accrued Losses	—
Payments	(3)
Balance at December 31, 2024	$	82

As of December 31, 2024, the Utility recorded an insurance receivable of $90 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of December 31, 2024, the Utility also recorded a $7 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 $53 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, through rates, and from 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,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2024 are:

Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	527	$	90
FERC TO rates	94		7
WEMA	508		53
Wildfire Fund	925		—
Probable recoveries at December 31, 2024 (1)	$	2,054	$	150

(1) Includes legal costs of $123 million and $50 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2024.

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

Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.

Insurance Receivable

As of December 31, 2024, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $527 million and $90 million in connection with 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. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2023:

Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2023	$	326	$	63	$	389
Accrued insurance recoveries	1		27		28
Reimbursements	(300)		—		(300)
Balance at December 31, 2024	$	27	$	90	$	117

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 reasonableness 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, 2024, the Utility recorded reductions of $94 million and $7 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, 2024, 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 $508 million and $53 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund under AB 1054

On July 12, 2019, AB 1054 became law. The law 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 arising from wildfires 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, 2024 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. This reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the IOU’s electric transmission and distribution rate base in the year of the prudency determination. A utility would not be required to reimburse the Wildfire Fund for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Utility, the disallowance cap would be approximately $4.1 billion for 2024. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2024 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. 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 11, 2024, the OEIS approved the Utility’s 2024 application and issued the Utility’s 2024 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts in the fund are exhausted. The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable 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 the participating 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 PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, 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. AB 1054 authorizes the reimbursement of funds where a participating utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

As of December 31, 2024, PG&E Corporation and the Utility recorded $600 million and $156 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2023:

Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2023	$	600
Accrued Wildfire Fund recoveries	325
Claims paid by Wildfire Fund	(169)
Balance at December 31, 2024	$	756

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” 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, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, 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 due to the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, 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 settlement.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its 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.

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 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 of 1933, as amended, 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 former officers and directors, and the underwriters. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation.

On August 21, 2024, the District Court entered an order setting a briefing schedule for renewed motions to dismiss the third amended complaint. Opening briefs were filed on October 24, 2024, opposition briefs were filed December 20, 2024, and reply briefs were filed January 31, 2025.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and proceeds from any insurance 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. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities 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. Such claims could 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 January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing 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.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with 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 continue to prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations

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.

PG&E Corporation and the Utility additionally may have 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 March 28, 2025.

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 assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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

Rates under the TO rate case for 2017 (“TO18”) were in effect from March 1, 2017 through February 28, 2018. Rates under the TO rate case for 2018 (“TO19”) were in effect from March 1, 2018 through April 30, 2019. Rates under the TO rate case for 2019 (“TO20”) were in effect from May 1, 2019 through December 31, 2023. The FERC previously approved settlement agreements for TO19 and TO20 resolving most issues.

On May 31, 2024, the Utility submitted a settlement to the FERC resolving all outstanding issues in the TO18, TO19, and TO20 rate cases. On August 22, 2024, the FERC approved the settlement. As a result, the Utility will refund $236 million, $358 million, and $405 million (plus applicable interest) to retail customers for TO18, TO19, and TO20, respectively. Approval of the settlement did not have a material impact on the Utility’s financial statements in the year ended December 31, 2024. The refunds will occur over 12 months, effective January 1, 2025. The settlement provided that the Utility may seek authorization from the CPUC through a memorandum account to recover up to $473 million through CPUC jurisdictional rates of the general, common and intangible plant cost that had been allocated to FERC-jurisdictional rates in TO18, TO19, and TO20.

2022 WMCE Interim Rate Relief Subject to Refund

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 the implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

2023 WMCE Interim Rate Relief Subject to Refund

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 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 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

On September 16, 2024, the CPUC issued a final decision on interim rate that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

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 $74 million and $89 million as of December 31, 2024 and December 31, 2023, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.

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 Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2024		December 31, 2023
Topock natural gas compressor station	$	294	$	276
Hinkley natural gas compressor station	97		104
Former MGP sites owned by the Utility or third parties (1)	782		809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	76		107
Fossil fuel-fired generation facilities and sites (3)	18		19
Total environmental remediation liability	$	1,267	$	1,315

(1) Primarily driven by the following sites: San Francisco Beach Street, 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 EPA 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, 2024, 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, 2024, the Utility expected to recover $1.1 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. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $211 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’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 action to meet interim cleanup targets. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $123 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. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $637 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. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 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. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $16 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 European Mutual Association for Nuclear Insurance (“EMANI”), covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

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 DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident (including terrorism and cybersecurity) and $2.5 billion per non-nuclear incident for DCPP. For Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. These coverage amounts are shared by all NEIL members. EMANI shares losses with NEIL as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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 $42 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $500 million for DCPP. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 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 $500 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, 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, 2024:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Natural Gas		Other (1)		Total
2025	$	2,010	$	910	$	443	$	354	$	3,717
2026	1,952		866		348		162		3,328
2027	1,896		800		190		284		3,170
2028	1,875		800		103		141		2,919
2029	1,831		716		92		43		2,682
Thereafter	14,229		2,730		41		5		17,005
Total purchase commitments	$	23,793	$	6,822	$	1,217	$	989	$	32,821

(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, qualifying facilities (“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 2025 and 2045.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement 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 2025 and 2044.

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, 2024, QF contracts in operation expire at various dates between 2025 and 2042.  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 $2.1 billion in 2024, $2.4 billion in 2023, and $2.8 billion in 2022.

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 along with a facility associated with a third party tolling agreement.  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 2025 and 2042.  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 $0.8 billion in 2024, $2.5 billion in 2023, and $2.4 billion in 2022.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2025 and 2030 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 $294 million in 2024, $180 million in 2023, and $44 million in 2022.

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 2025 and 2058, as well as other multi-year agreements.  At December 31, 2024, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2025	$	84
2026	44
2027	47
2028	37
2029	34
Thereafter	333
Total minimum payments	$	579

Payments for other commitments were $105 million in 2024, $106 million in 2023, and $63 million in 2022.  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 $650 million is to be made in 2025. If the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution of up to $775 million in 2040. The Utility also will share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

Additionally, the Utility agreed to purchase the Lakeside Building for $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. See “Oakland Headquarters Lease and Purchase” in Note 2 above.

XML

SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT

12 Months Ended

Dec. 31, 2024

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT

PG&E CORPORATION

SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2024		2023		2022
Administrative service revenue	$	146	$	154	$	109
Operating expenses	(167)		(165)		(193)
Interest income	15		13		3
Interest expense	(270)		(365)		(261)
Other income (expense)	(17)		(21)		(201)
Equity in earnings of subsidiaries	2,697		2,530		2,154
Income Before Income Taxes	2,404		2,146		1,611
Income tax benefit	(94)		(96)		(132)
Net Income	$	2,498	$	2,242	$	1,743
Preferred stock dividend requirement	23		—		—
Income Available for Common Shareholders	$	2,475	$	2,242	$	1,743
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)		(16)		21
Net unrealized gain on available-for-sale securities (net of taxes of $0, $0, and $0, respectively)	1		—		—
Total other comprehensive income (loss)	(6)		(16)		21
Comprehensive Income	$	2,469	$	2,226	$	1,764
Weighted Average Common Shares Outstanding, Basic	2,141		2,064		2,235
Weighted Average Common Shares Outstanding, Diluted	2,147		2,138		2,380
Net Earnings Per Common Share, Basic	$	1.16	$	1.09	$	0.78
Net Earnings Per Common Share, Diluted	$	1.15	$	1.05	$	0.73

PG&E CORPORATION

SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONSOLIDATED BALANCE SHEETS

	Balance at December 31,
(in millions)	2024		2023
ASSETS
Current Assets
Cash and cash equivalents	$	235	$	192
Restricted cash and restricted cash equivalents	1		3
Advances to affiliates	13		24
Income taxes receivable	2		2
Other current assets	—		1
Total current assets	251		222
Other Noncurrent Assets
Investments in subsidiaries	42,829		36,804
Other investments	175		167
Deferred income taxes	633		539
Total other noncurrent assets	43,637		37,510
TOTAL ASSETS	$	43,888	$	37,732
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable – other	36		58
Income taxes payable	1		1
Other current liabilities	420		363
Total current liabilities	457		422
Noncurrent Liabilities
Long-term debt	5,612		4,599
Other noncurrent liabilities	141		141
Total noncurrent liabilities	5,753		4,740
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		—
Common stock	39,086		37,906
Reinvested earnings	(2,966)		(5,322)
Accumulated other comprehensive loss	(21)		(14)
Total shareholders’ equity	37,678		32,570
TOTAL LIABILITIES AND EQUITY	$	43,888	$	37,732

PG&E CORPORATION

SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2024		2023		2022
Cash Flows from Operating Activities:
Net income	$	2,498	$	2,242	$	1,743
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	53		4		95
Equity in earnings of subsidiaries	(2,699)		(2,530)		(2,160)
Deferred income taxes and tax credits, net	(94)		(116)		(126)
Current income taxes payable	—		9		—
Other	9		40		339
Net cash used in operating activities	(233)		(351)		(109)
Cash Flows From Investing Activities:
Investment in subsidiaries	(5,360)		(1,290)		(994)
Dividends received from subsidiaries (1)	2,025		1,775		1,275
Net cash provided by (used in) investing activities	(3,335)		485		281
Cash Flows From Financing Activities:
Repayments under term loan credit facilities	(500)		(2,181)		—
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates	—		2,123		—
Repayment of long-term debt	—		—		(28)
Repayments of intercompany note from the Utility	—		—		(145)
Proceeds from issuance of long-term debt, net of premium and    issuance costs of $4, $0, and $0 at respective dates	1,496		—		—
Common stock issued	1,128		—		—
Mandatory convertible preferred stock issued	1,579		—		—
Common stock dividend paid	(86)		—		—
Other	(8)		(6)		—
Net cash provided by (used in) financing activities	3,609		(64)		(173)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	41		70		(1)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	195		125		126
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	236	$	195	$	125
Less: Restricted cash and restricted cash equivalents	(1)		(3)		—
Cash and cash equivalents at December 31	$	235	$	192	$	125
Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(215)	$	(309)	$	(233)
Supplemental disclosures of noncash investing and financing activities
Changes to PG&E Corporation common stock and treasury stock in connection     with the share exchange with the Fire Victim Trust	$	—	$	(2,517)	$	(2,337)
Common stock dividends declared but not yet paid	55		21		—
Mandatory convertible preferred stock dividends declared but not yet paid	23		—		—

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

XML

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2024

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, 2024, 2023, and 2022

(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:
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166

(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, 2024, 2023, and 2022

(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:
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166

(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.

XML

Insider Trading Arrangements

3 Months Ended

12 Months Ended

Dec. 31, 2024

shares

Dec. 31, 2024

shares

Trading Arrangements, by Individual

Material Terms of Trading Arrangement

On November 14, 2024, Kerry W. Cooper, who serves as the Chair of the Board of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of up to 6,800 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of December 16, 2025 or the execution of the sale of all 6,800 shares.

On November 15, 2024, Carla J. Peterman, who serves as the Executive Vice President, Corporate Affairs and Chief Sustainability Officer of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of an indeterminate number of shares of PG&E Corporation common stock. The number of shares that may be sold under this Rule 10b5-1 trading arrangement will vary based on the number of shares that Ms. Peterman receives when her performance share units (“PSUs”) vest. The maximum number of shares to be sold will be reduced by shares withheld to satisfy tax withholding obligations that arise in connection with the vesting and settlement. The trading arrangement will terminate on the earlier of June 27, 2025 or the execution of the sale of all covered shares.

On November 18, 2024, Marlene M. Santos, who serves as the Executive Vice President and Chief Customer and Enterprise Solutions Officer of the Utility, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of an indeterminate number of shares of PG&E Corporation common stock. The number of shares that may be sold under this Rule 10b5-1 trading arrangement will vary based on the number of shares that Ms. Santos receives when her PSUs vest. The maximum number of shares to be sold will be reduced by shares withheld to satisfy tax withholding obligations that arise in connection with the vesting and settlement. The trading arrangement will terminate on the earlier of June 27, 2025 or the execution of the sale of all covered shares.

Non-Rule 10b5-1 Arrangement Adopted

false

Rule 10b5-1 Arrangement Terminated

false

Non-Rule 10b5-1 Arrangement Terminated

false

Kerry W. Cooper [Member]

Trading Arrangements, by Individual

Name

Kerry W. Cooper

Title

Chair of the Board

Rule 10b5-1 Arrangement Adopted

true

Adoption Date

November 14, 2024

Expiration Date

December 16, 2025

Arrangement Duration

397 days

Aggregate Available

6,800

6,800

Carla J. Peterman [Member]

Trading Arrangements, by Individual

Name

Carla J. Peterman

Title

Executive Vice President, Corporate Affairs and Chief Sustainability Officer

Rule 10b5-1 Arrangement Adopted

true

Adoption Date

November 15, 2024

Expiration Date

June 27, 2025

Arrangement Duration

224 days

Marlene Santos [Member]

Trading Arrangements, by Individual

Name

Marlene M. Santos

Title

Executive Vice President and Chief Customer and Enterprise Solutions Officer

Rule 10b5-1 Arrangement Adopted

true

Adoption Date

November 18, 2024

Expiration Date

June 27, 2025

Arrangement Duration

221 days

XML

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

XML

Cybersecurity Risk Management and Strategy Disclosure

12 Months Ended

Dec. 31, 2024

Cybersecurity Risk Management, Strategy, and Governance [Line Items]

Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]

The objective of PG&E Corporation’s and the Utility’s cybersecurity program is to protect information assets and to mitigate against material cybersecurity threats, data and information compromise, and other risk events that could materially affect the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk, such as:

•Developing organizational understanding in managing cybersecurity risks to systems, assets, and data by regularly assessing cybersecurity internal controls and program maturity, including engaging independent third parties and participating in external regulatory compliance assessments;

•Assessing, monitoring, and imposing contractual requirements on third-party service providers for cybersecurity risks and for compliance with PG&E Corporation’s and the Utility’s policies regarding access to company networks, information security, and technology;

•Configuring and monitoring the system; employing policies, controls, and security tools, including training for employees and contractors; and limiting access and operating firewall rules as necessary and appropriate;

•Utilizing multiple government and private assessors, consultants, auditors or other third parties, as well as an internal team, for intelligence gathering, security monitoring, threat hunting, and forensic activities;

•Monitoring emerging data protection laws and regulations and implementing changes to processes designed to comply with any such laws and regulations;

•Responding to cybersecurity incidents as they are detected by containing consequences, investigating causes and impacts, and implementing mitigations;

•Maintaining and utilizing plans for resilience, mitigation, and restoring any capabilities or services that were impaired due to a cybersecurity incident;

•Maintaining cybersecurity liability insurance;

•Maintaining physical controls on a risk-informed basis, including controlling access or monitoring as appropriate; and

•Continuously improving the cybersecurity program by incorporating learning from past experiences and testing, reviewing, and enhancing the controls and capabilities discussed above, including conducting regular cybersecurity incident-response exercises.

PG&E Corporation and the Utility have identified cybersecurity as a key enterprise risk, which they manage through their enterprise risk management system.

PG&E Corporation and the Utility have not experienced any cybersecurity incidents in the last three years that have materially affected the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. For more information regarding how cybersecurity threats could materially affect PG&E Corporation and the Utility, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack.” in Item 1A. Risk Factors.

Cybersecurity Risk Management Processes Integrated [Flag]

true

Cybersecurity Risk Management Processes Integrated [Text Block]

PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk,

Cybersecurity Risk Management Third Party Engaged [Flag]

true

Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]

true

Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]

false

Cybersecurity Risk Board of Directors Oversight [Text Block]

PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, have primary responsibility for overseeing cybersecurity risk management, including reviewing the companies’ cybersecurity policies, controls, and procedures. The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats. In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.

Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]

The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats.

Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]

In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies.

Cybersecurity Risk Role of Management [Text Block]

The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats. In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.

The Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions. They are responsible for assessing and managing cybersecurity risks in collaboration with the enterprise risk management team. Such persons are informed about cybersecurity vulnerabilities and incidents through daily and weekly operating reviews conducted by management and personnel closest to the work as part of the Lean operating system and as otherwise appropriate.

Cybersecurity Risk Management Positions or Committees Responsible [Flag]

true

Cybersecurity Risk Management Positions or Committees Responsible [Text Block]

The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats.

Cybersecurity Risk Management Expertise of Management Responsible [Text Block]

The Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions.

Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]

In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.

Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]

true

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2024

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.

Segment Reporting

Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the chief operating decision maker uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.

Cash, Cash Equivalents, and Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2024 and 2023, the Utility also held $272 million and $294 million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

As of December 31, 2024, the Utility had contributed $911 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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 through 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, 2024, 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.

Expected credit losses of $341 million, $636 million, and $143 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2024, 2023, and 2022, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively. As of December 31, 2023, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $507 million and $78 million, respectively. The RUBA current balancing account balance decreased from December 31, 2023 to December 31, 2024 primarily due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

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. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. 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 for use 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 allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” 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 in 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 3.61% in 2024, 3.56% in 2023, and 3.74% in 2022.  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.

Allowance for Funds Used During Construction

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 3 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 estimated decommissioning dates. 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 cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, 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 plant. 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 using a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2024 and December 31, 2023 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2024, the Utility recorded a $222 million reduction to the nuclear decommissioning ARO to reflect the NRC’s decision to grant DCPP’s extended operations until 2030. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

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 Obligation and Trusts

The Utility’s nuclear generation facilities consist of two units at DCPP and the Humboldt Bay independent spent fuel storage installation.  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.

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

The Utility participated in various government assistance programs during the years ended December 31, 2024, 2023, and 2022. 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, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, 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. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, 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 pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for DCPP Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of DCPP. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility received the final proceeds from the DWR loan agreement in 2024. For more information, see the DWR loan activity table below.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:

(in millions)	2024		2023		2022
Long-term debt:
Beginning Balance - DWR loan outstanding	$	98	$	312	$	—
Proceeds received	980		—		350
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(117)		(124)		(38)
Operating and maintenance expense - Loan forgiveness and other adjustments	(75)		(90)		—
Long-term debt:
Ending Balance - DWR loan outstanding	$	886	$	98	$	312

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are 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 a number of factors, including actual costs incurred to extend the DCPP operations. 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 recognizes such funding as income and records a receivable related to government grants. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $265 million and $115 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $138 million and $76 million, as a deduction to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP.

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 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2024 and December 31, 2023, the SPV had net accounts receivable of $3.2 billion and $2.7 billion, respectively, and outstanding borrowings of zero and $1.5 billion respectively, under the Receivables Securitization Program. For more information, see Note 4 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 orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Recovery Funding LLC had outstanding borrowings of $3.2 billion and $1.8 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets.

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 first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate 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 the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.2 billion and $7.3 billion 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.

Non-Consolidated VIEs

Power Purchase Agreements

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, 2024, the Utility 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, 2024, it did not consolidate any of them.

The Lakeside Building

BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building, which serves as the Utility’s principal administrative headquarters.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property, and the Utility does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to an issued letter of credit, base rent, and certain costs it pays according to the office lease agreement. As a result, the Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC. For more information, see “Oakland Headquarters Lease and Purchase” in Note 15 below.

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 it can ascertain an implicit discount rate from the leasing arrangement. 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 as paid in conformity with ratemaking.

Financing Leases

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets.

Accounting Standards Issued But Not Yet Adopted

Recently Adopted Accounting Standards

Segment Reporting

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amended the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. PG&E Corporation and the Utility adopted this ASU in December 2024. See “Segment Reporting” above for additional disclosures as a result of adopting this ASU. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and income taxes paid disaggregated by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. PG&E Corporation and the Utility do not expect the guidance to have a significant impact on their Consolidated Financial Statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

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, 2024

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)	2024		2023		2022
Electric
Revenue from contracts with customers
Residential	$	7,504	$	6,041	$	6,130
Commercial	7,201		5,643		5,416
Industrial	2,065		1,784		1,626
Agricultural	1,815		1,413		1,830
Public street and highway lighting	103		83		77
Other, net (1)	(47)		136		(247)
Total revenue from contracts with customers - electric	18,641		15,100		14,832
Regulatory balancing accounts (2)	(830)		2,324		228
Total electric operating revenue	$	17,811	$	17,424	$	15,060
Natural gas
Revenue from contracts with customers
Residential	$	3,089	$	3,686	$	3,353
Commercial	984		1,052		1,005
Transportation service only	1,815		1,603		1,534
Other, net (1)	159		(145)		163
Total revenue from contracts with customers - gas	6,047		6,196		6,055
Regulatory balancing accounts (2)	561		808		565
Total natural gas operating revenue	6,608		7,004		6,620
Total operating revenues	$	24,419	$	24,428	$	21,680

(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 alternative 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)	2024		2023
Electricity generating facilities (1)	1 to 75	$	11,420	$	11,423
Electricity distribution facilities	10 to 70	49,821		45,205
Electricity transmission facilities	15 to 75	18,481		17,562
Natural gas distribution facilities	15 to 60	17,213		16,324
Natural gas transmission and storage facilities	15 to 68	11,117		10,496
General plant and other	5 to 50	10,210		9,165
Financing lease		814		787
Construction work in progress		4,458		4,452
Total property, plant, and equipment		123,534		115,414
Accumulated depreciation		(35,304)		(33,093)
Net property, plant, and equipment (2)		$	88,230	$	82,321

(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below. Nuclear generating facilities have been authorized by the CPUC to be fully depreciated by December 31, 2025.

(2) Includes $3.0 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.

Changes In Asset Retirement Obligations

The following table summarizes the changes in ARO during 2024 and 2023, including nuclear decommissioning obligations:

(in millions)	2024		2023
ARO liability at beginning of year	$	5,512	$	5,912
Revision in estimated cash flows	(290)		(585)
Accretion	269		253
Liabilities settled	(47)		(68)
ARO liability at end of year	$	5,444	$	5,512

Schedule Of Government Assistance

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:

(in millions)	2024		2023		2022
Long-term debt:
Beginning Balance - DWR loan outstanding	$	98	$	312	$	—
Proceeds received	980		—		350
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(117)		(124)		(38)
Operating and maintenance expense - Loan forgiveness and other adjustments	(75)		(90)		—
Long-term debt:
Ending Balance - DWR loan outstanding	$	886	$	98	$	312

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, 2024 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
Beginning balance	$	(28)	$	18	$	2	$	(8)
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively)	—		—		1		1
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively)	(268)		29		—		(239)
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively)	260		(29)		—		231
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(2)		2		—		—
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively) (1)	1		(16)		—		(15)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)	2		14		—		16
Net current period other comprehensive income	(7)		—		1		(6)
Ending balance	$	(35)	$	18	$	3	$	(14)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2023 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		8		8
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively)	(196)		73		—		(123)
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively)	180		(73)		—		107
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(3)		2		—		(1)
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively)(1)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1)	2		12		—		14
Net current period other comprehensive income (loss)	(16)		—		8		(8)
Ending balance	$	(28)	$	18	$	2	$	(8)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

Schedule of Lease Expense

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

	Year Ended December 31,
(in millions)	2024		2023
Financing lease fixed cost:
Amortization of ROU assets	$	274	$	115
Interest on lease liabilities	42		27
Financing lease variable cost	9		3
Total financing lease costs	$	325	$	145

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

	Year Ended December 31,
(in millions)	2024		2023		2022
Operating lease fixed cost	$	116	$	269	$	500
Operating lease variable cost	1,524		1,632		1,829
Total operating lease costs	$	1,640	$	1,901	$	2,329

Schedule of Future Expected Operating Lease Payments

At December 31, 2024, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2024
2025	$	116
2026	112
2027	110
2028	97
2029	62
Thereafter	195
Total lease payments	692
Less imputed interest	(173)
Total	$	519

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)

12 Months Ended

Dec. 31, 2024

Regulated Operations [Abstract]

Long-Term Regulatory Assets

Noncurrent regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2024		2023
Pension benefits (1)	$	673	$	348	Indefinitely
Environmental compliance costs	1,172		1,218		32 years
Price risk management	167		160		up to 15.5 years
Catastrophic event memorandum account (2)	742		1,074		Various
Wildfire-related accounts (3)	1,697		2,915		1 - 3 years
Deferred income taxes (4)	4,771		3,543		Various
Financing costs (5)	216		196		Various
SB 901 securitization (6)	5,194		5,249		28 years
General rate case memorandum accounts (7)	95		1,291		Various
Other	834		1,195		Various
Total noncurrent regulatory assets	$	15,561	$	17,189

(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) 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, 2024 and 2023, $1 million and $43 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FHPMA, FRMMA, WMPMA, WMBA, VMBA and MGMA.

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

(5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings.

(6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds 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 5 below.

(7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 relates to revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022.

Long-Term Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2024		2023
Cost of removal obligations (1)	$	8,943	$	8,191
Public purpose programs (2)	1,112		1,238
Employee benefit plans (3)	1,088		1,032
Transmission tower wireless licenses (4)	306		384
SFGO sale (5)	79		185
SB 901 securitization (6)	6,295		6,628
Wildfire self-insurance (7)	804		407
Other	790		1,379
Total noncurrent regulatory liabilities	$	19,417	$	19,444

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

(2) 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.

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

(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. Of the $306 million, $273 million will be refunded to FERC-jurisdictional customers, and $33 million will be refunded to CPUC-jurisdictional customers.

(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.

(6) 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. See Note 5 below.

(7) Represents amounts collected through rates designated for wildfire self-insurance. See Note 14 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)	2024		2023
Electric distribution (1)	$	1,591	$	1,092
Electric transmission (2)	117		99
Gas distribution and transmission (3)	387		144
Energy procurement (4)	1,066		1,002
Public purpose programs (5)	162		137
Wildfire-related accounts (6)	979		568
Insurance premium costs (7)	38		227
Residential uncollectibles balancing accounts (8)	260		507
Catastrophic event memorandum account (9)	500		413
General rate case memorandum accounts (10)	1,113		1,097
Other	1,014		374
Total regulatory balancing accounts receivable	$	7,227	$	5,660

Current Regulatory Balancing Accounts Payable

	Payable Balance at December 31,
(in millions)	2024		2023
Electric transmission (2)	$	883	$	200
Gas distribution and transmission (3)	72		224
Energy procurement (4)	329		77
Public purpose programs (5)	882		299
SFGO sale	93		79
Wildfire-related accounts (6)	337		125
Nuclear decommissioning adjustment mechanism (11)	23		216
Other	550		449
Total regulatory balancing accounts payable	$	3,169	$	1,669

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

(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases.

(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(4) 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.

(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA.

(7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC.

(8) 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. The RUBA balance decreased from December 31, 2023 to December 31, 2024 mainly due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025.

(9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, and final decision on the 2023 WMCE interim rate relief.

(10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.

(11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision.

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DEBT (Tables)

12 Months Ended

Dec. 31, 2024

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 as of December 31, 2024:

(in millions)	Termination Date		Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2029	(1)	$	4,400	(2)	$	—	$	(633)	$	3,767
Utility Receivables Securitization Program (3)	June 2026		1,500		(4)	—		—		1,500		(4)
PG&E Corporation revolving credit facility	June 2027		500			—		—		500
Total credit facilities			$	6,400		$	—	$	(633)	$	5,767

(1) On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

(2) Includes a $2.0 billion letter of credit sublimit.

(3) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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, 2024		December 31, 2023
PG&E Corporation
Term Loan	7.85%	$	—	$	500
Convertible Notes due 2027	4.25%	2,150		2,150
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Junior Subordinated Notes due 2055	7.38%	1,500		—
Unamortized discount, premium and debt issuance costs, net		(39)		(51)
Total PG&E Corporation Long-Term Debt		5,611		4,599
Utility
First Mortgage Bonds - Stated Maturity:
2024	3.40% - 3.75%	—		800
2025	3.45% - 4.95%	1,925		1,925
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 4.65%	1,975		1,975
2029	4.20% - 6.10%	2,100		1,250
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		1,050
2033	6.15% - 6.40%	1,900		1,900
2034	5.80% - 6.95%	1,900		800
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		550
2053	6.70% - 6.75%	2,300		2,000
2054	5.90%	750		—
Less: current portion, net of unamortized discount and debt issuance costs		(1,924)		(800)
Unamortized discount, premium and debt issuance costs, net		(226)		(246)
Total Utility First Mortgage Bonds		36,927		35,831
Recovery Bonds (1)		10,367		9,124
Less: current portion		(222)		(176)
DWR Loan (2)		886		98
Credit Facilities
Receivables Securitization Program	6.75%	—		1,499
2-Year Term Loan	6.60%	—		400
Less: current portion		—		(400)
Total Utility Long-Term Debt		47,958		46,376
Total PG&E Corporation Consolidated Long-Term Debt		$	53,569	$	50,975

(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.

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, 2024 are reflected in the table below:

(in millions, except interest rates)	2025			2026			2027			2028			2029			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	4.25		%	5.00		%	—		%	6.53		%	5.39		%
Fixed rate obligations	$	—		$	—		$	2,150		$	1,000		$	—		$	2,500		$	5,650
Utility (1)
Average fixed interest rate	3.82		%	3.10		%	3.22		%	3.58		%	5.52		%	4.72		%	4.44		%
Fixed rate obligations	$	1,925		$	2,551		$	3,000		$	1,975		$	2,100		$	27,526		$	39,077
Recovery Bonds (2)
AB 1054 obligations	$	88		$	81		$	84		$	88		$	91		$	2,728		$	3,160
SB 901 obligations	135			140			146			152			159			6,475			7,207
Total consolidated debt	$	2,148		$	2,772		$	5,380		$	3,215		$	2,350		$	39,229		$	55,094

(1) The balance excludes DWR loan, see Note 2 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and “AB 1054 Securitization” above. For SB 901 interest rates, see the 2022 Form 10-K.

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Tables)

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

Schedule of Financial Statement Impact of Securitization

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:

	SB 901 securitization regulatory asset
(in millions)	2024		2023
Balance at January 1	$	5,249	$	5,378
Amortization	(55)		(129)
Balance at December 31	$	5,194	$	5,249

	SB 901 securitization regulatory liability
(in millions)	2024		2023
Balance at January 1	$	(6,628)	$	(5,800)
Amortization	383		451
Additions(1)	(50)		(1,279)
Balance at December 31	$	(6,295)	$	(6,628)

(1) Includes $16 million and $12 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2024 and 2023, respectively.

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COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2024

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 2024:

(in millions)	2024		2023		2022
Restricted stock units	67		64		60
Performance shares	31		27		55
Total compensation expense (pre-tax)	$	98	$	91	$	115
Total compensation expense (after-tax)	$	71	$	65	$	83

Summary of Stock Option Activity

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2024:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1	1,396,261	$	8.2
Granted (1)	—	—
Exercised	—	—
Forfeited or expired	(652,298)	6.89
Outstanding at December 31	743,963	10.23		2.58
Vested or expected to vest at December 31	743,963	10.23		2.58
Exercisable at December 31	743,963	$	10.23	2.58

(1) Represents additional payout of existing stock option grants.

Schedule of Restricted Stock Units

The following table summarizes restricted stock unit activity for 2024:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	9,268,425	$	13.29
Granted	5,273,850	16.74
Vested	(4,922,000)	12.62
Forfeited	(196,693)	15.27
Nonvested at December 31	9,423,582	$	15.52

Schedule of Performance Shares

The following table summarizes activity for performance shares in 2024:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	6,602,292	$	14.06
Granted	2,714,196	16.94
Vested	(1,779,695)	10.70
Forfeited	(356,587)	13.07
Nonvested at December 31	7,180,206	$	15.52

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2024

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 2024, 2023, and 2022.

	Year Ended December 31,
(in millions, except per share amounts)	2024		2023		2022
Income (loss) available for common shareholders	$	2,475	$	2,242	$	1,800
Weighted average common shares outstanding, basic (1)	2,141		2,064		1,987
Add incremental shares from assumed conversions:
Employee share-based compensation	6		6		8
Equity Units	—		68		137
Weighted average common shares outstanding, diluted	2,147		2,138		2,132
Total earnings (loss) per common share, diluted	$	1.15	$	1.05	$	0.84

(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2024

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2024		2023		2022		2024		2023		2022
Current:
Federal	$	2	$	(1)	$	(1)	$	2	$	(1)	$	(1)
State	(78)		—		—		(78)		—		—
Deferred:
Federal	(137)		(1,047)		(943)		(72)		(981)		(852)
State	15		(507)		(389)		45		(477)		(348)
Tax credits	(2)		(2)		(5)		(2)		(2)		(5)
Income tax benefit	$	(200)	$	(1,557)	$	(1,338)	$	(105)	$	(1,461)	$	(1,206)

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)	2024		2023		2024		2023
Deferred income tax assets:
Tax carryforwards	$	9,429	$	9,132	$	8,955	$	8,740
Compensation	171		145		86		82
GHG allowance	471		361		471		361
Wildfire-related claims (1)	295		1,069		295		1,069
Operating lease liability	78		142		78		142
Transmission tower wireless licenses	251		250		251		250
Bad debt	127		134		127		134
Other (2)	140		130		137		109
Total deferred income tax assets	$	10,962	$	11,363	$	10,400	$	10,887
Deferred income tax liabilities:
Property-related basis differences	11,021		10,058		11,009		10,047
Regulatory balancing accounts	878		1,433		878		1,433
Debt financing costs	390		428		390		428
Operating lease ROU asset	78		142		78		142
Income tax regulatory asset (3)	1,335		991		1,335		991
Environmental reserve	248		200		248		200
Other (4)	94		91		94		82
Total deferred income tax liabilities	$	14,044	$	13,343	$	14,032	$	13,323
Total net deferred income tax liabilities	$	3,082	$	1,980	$	3,632	$	2,436

(1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in 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 TCJA.

(4) Amounts primarily include property taxes and prepaid expense.

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,
	2024		2023		2022		2024		2023		2022
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)	(2.0)		(57.9)		(75.8)		(0.8)		(34.4)		(26.9)
Effect of regulatory treatment of fixed asset differences (2)	(28.3)		(63.4)		(123.8)		(24.7)		(40.1)		(49.2)
Tax credits	(0.7)		(2.2)		(3.2)		(0.7)		(2.2)		(1.3)
Fire Victim Trust (3)	—		(126.9)		(160.9)		—		(80.2)		(64.0)
Other, net (4)	1.2		2.2		12.9		1.2		1.1		2.2
Effective tax rate	(8.8)	%	(227.2)	%	(329.8)	%	(4.0)	%	(134.8)	%	(118.2)	%

(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 2024, 2023, and 2022, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA passed in December 2017. In addition, for the 2024 tax year, PG&E Corporation and the Utility will implement the accounting method change related to gas repairs in accordance with Revenue Procedure 2013-15.

(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023 and 2022 and a deferred tax asset write-off associated with the grantor trust election for the Fire Victim Trust in 2021.

(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)	2024		2023		2022		2024		2023		2022
Balance at beginning of year	$	616	$	570	$	498	$	616	$	570	$	498
Additions for tax position taken during a prior year	—		1		—		—		1		—
Reductions for tax position taken during a prior year	(257)		—		(1)		(257)		—		(1)
Additions for tax position taken during the current year	95		45		73		95		45		73
Settlements	—		—		—		—		—		—
Balance at end of year	$	454	$	616	$	570	$	454	$	616	$	570

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, 2024		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,369	2031 - 2036
Net operating loss carryforward - Post-2017	30,288		N/A
Tax credit carryforward	125		2029 - 2041
State:
Net operating loss carryforward	$	34,901	2039 - 2041
Tax credit carryforward	146		Various

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2024

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, 2024	December 31, 2023
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	179,257,247	196,063,296
	Options	37,717,500	30,695,000
Electricity (MWh)	Forwards, futures, and swaps	8,576,078	9,169,967
	Options	1,663,200	92,400
	Congestion Revenue Rights (3)	123,040,895	170,465,674

(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, 2024, 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	$	186	$	(16)	$	—	$	170
Noncurrent assets – other	233		—		—		233
Current liabilities – other	(152)		16		—		(136)
Noncurrent liabilities – other	(167)		—		—		(167)
Total commodity risk	$	100	$	—	$	—	$	100

As of December 31, 2023, 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	$	134	$	(8)	$	50	$	176
Other noncurrent assets – other	280		—		—		280
Current liabilities – other	(172)		8		46		(118)
Noncurrent liabilities – other	(160)		—		—		(160)
Total commodity risk	$	82	$	—	$	96	$	178

Offsetting Assets

As of December 31, 2024, 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	$	186	$	(16)	$	—	$	170
Noncurrent assets – other	233		—		—		233
Current liabilities – other	(152)		16		—		(136)
Noncurrent liabilities – other	(167)		—		—		(167)
Total commodity risk	$	100	$	—	$	—	$	100

As of December 31, 2023, 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	$	134	$	(8)	$	50	$	176
Other noncurrent assets – other	280		—		—		280
Current liabilities – other	(172)		8		46		(118)
Noncurrent liabilities – other	(160)		—		—		(160)
Total commodity risk	$	82	$	—	$	96	$	178

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2024

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, 2024
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	826	$	—	$	—	$	—	$	826
Pacific Energy Risk Solutions, LLC
Short-term investments	905		—		—		—		905
Total Pacific Energy Risk Solutions, LLC	905		—		—		—		905
Nuclear decommissioning trusts
Short-term investments	53		—		—		—		53
Global equity securities	2,228		—		—		—		2,228
Fixed-income securities	1,250		1,027		—		—		2,277
Assets measured at NAV	—		—		—		—		22
Total nuclear decommissioning trusts (2)	3,531		1,027		—		—		4,580
Customer credit trust
Short-term investments	1		—		—		—		1
Global equity securities	186		—		—		—		186
Fixed-income securities	46		144		—		—		190
Total customer credit trust	233		144		—		—		377
Price risk management instruments (Note 10)
Electricity	—		26		383		(6)		403
Gas	—		10		—		(10)		—
Total price risk management instruments	—		36		383		(16)		403
Rabbi trusts
Short-term investments	107		—		—		—		107
Global equity securities	6		—		—		—		6
Life insurance contracts	—		66		—		—		66
Total rabbi trusts	113		66		—		—		179
Long-term disability trust
Short-term investments	4		—		—		—		4
Assets measured at NAV	—		—		—		—		130
Total long-term disability trust	4		—		—		—		134
TOTAL ASSETS	$	5,612	$	1,273	$	383	$	(16)	$	7,404
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	37	$	248	$	(6)	$	279
Gas	—		34		—		(10)		24
TOTAL LIABILITIES	$	—	$	71	$	248	$	(16)	$	303

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

(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	203	$	—	$	—	$	—	$	203
Nuclear decommissioning trusts
Short-term investments	52		—		—		—		52
Global equity securities	2,144		—		—		—		2,144
Fixed-income securities	1,168		909		—		—		2,077
Assets measured at NAV	—		—		—		—		18
Total nuclear decommissioning trusts (2)	3,364		909		—		—		4,291
Customer credit trust
Short-term investments	49		—		—		—		49
Global equity securities	71		—		—		—		71
Fixed-income securities	29		84		—		—		113
Total customer credit trust	149		84		—		—		233
Price risk management instruments (Note 10)
Electricity	—		7		404		(1)		410
Gas	—		3		—		43		46
Total price risk management instruments	—		10		404		42		456
Rabbi trusts
Short-term investments	102		—		—		—		102
Global equity securities	5		—		—		—		5
Life insurance contracts	—		65		—		—		65
Total rabbi trusts	107		65		—		—		172
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		139
Total long-term disability trust	7		—		—		—		146
TOTAL ASSETS	$	3,830	$	1,068	$	404	$	42	$	5,501
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	43	$	213	$	(6)	$	250
Gas	—		76		—		(48)		28
TOTAL LIABILITIES	$	—	$	119	$	213	$	(54)	$	278

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

(2) Represents amount before deducting $717 million, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurement Inputs and Valuation Techniques

	Fair Value
(in millions)	At December 31, 2024				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	366	$	121	Market approach	CRR auction prices	$ (951) - 50,044 / 2
Power purchase agreements	$	17	$	127	Discounted cash flow	Forward prices	$ 0 - 126 / 47

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

	Fair Value
(in millions)	At December 31, 2023				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	357	$	134	Market approach	CRR auction prices	$ (924) - 16,697 / 1
Power purchase agreements	$	47	$	79	Discounted cash flow	Forward prices	$ 1 - 190 / 60

(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, 2024 and 2023, respectively:

	Price Risk Management Instruments
(in millions)	2024		2023
Asset balance as of January 1	$	191	$	199
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(64)		(8)
Asset balance as of December 31	$	127	$	191

(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, 2024				At December 31, 2023
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	5,358	$	5,829	$	4,548	$	4,695
Utility	37,812		34,532		35,909		32,866

(1) As of December 31, 2024, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.

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, 2024
Nuclear decommissioning trusts
Short-term investments	$	54	$	—	$	(1)	$	53
Global equity securities	353		1,907		(10)		2,250
Fixed-income securities	2,341		20		(84)		2,277
Total (1)	$	2,748	$	1,927	$	(95)	$	4,580
As of December 31, 2023
Nuclear decommissioning trusts
Short-term investments	$	52	$	—	$	—	$	52
Global equity securities	381		1,792		(11)		2,162
Fixed-income securities	2,103		60		(86)		2,077
Total (1)	$	2,536	$	1,852	$	(97)	$	4,291

(1) Represents amounts before deducting $747 million and $717 million as of December 31, 2024 and December 31, 2023, 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, 2024
Less than 1 year	$	35
1–5 years	742
5–10 years	517
More than 10 years	983
Total maturities of fixed-income securities	$	2,277

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, 2024
Customer credit trust
Short-term investments	$	1	$	—	$	—	$	1
Global equity securities	161		28		(3)		186
Fixed-income securities	193		1		(4)		190
Total	$	355	$	29	$	(7)	$	377
As of December 31, 2023
Customer credit trust
Short-term investments	$	49	$	—	$	—	$	49
Global equity securities	56		16		(1)		71
Fixed-income securities	111		2		—		113
Total	$	216	$	18	$	(1)	$	233

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)	2024		2023		2022
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	1,980	$	2,235	$	3,316
Gross realized gains on securities	255		80		2
Gross realized losses on securities	(63)		(74)		(3)

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

	As of
(in millions)	December 31, 2024
Less than 1 year	$	—
1–5 years	44
5–10 years	36
More than 10 years	110
Total maturities of fixed-income securities	$	190

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

(in millions)	2024		2023		2022
Proceeds from sales and maturities of customer credit trust investments	$	398	$	556	$	250
Gross realized gains on securities	10		23		10
Gross realized losses on securities (1)	(8)		(19)		(41)

(1) Includes $0 million and $4 million of impaired debt securities which were written down to their respective fair values during the years ended December 31, 2024 and 2023, respectively.

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2024

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 2024 and 2023:

Pension Plan

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	17,211	$	16,369
Actual return on plan assets	218		1,518
Company contributions	337		336
Benefits and expenses paid	(999)		(1,012)
Fair value of plan assets at end of year	$	16,767	$	17,211
Change in benefit obligation:
Benefit obligation at beginning of year	$	17,697	$	16,608
Service cost for benefits earned	396		379
Interest cost	916		913
Actuarial loss (gain) (1)	(424)		809
Benefits and expenses paid	(1,000)		(1,012)
Benefit obligation at end of year (2)	$	17,585	$	17,697
Funded Status:
Current liability	$	(10)	$	(9)
Noncurrent liability	(808)		(477)
Net liability at end of year	$	(818)	$	(486)

(1) The actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions; the actuarial loss for the year ended December 31, 2023 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.3 billion at December 31, 2024 and 2023, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2024		2023
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,499	$	2,336
Actual return on plan assets	74		260
Company contributions	5		5
Plan participant contribution	84		81
Benefits and expenses paid	(191)		(183)
Fair value of plan assets at end of year	$	2,471	$	2,499
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,377	$	1,339
Service cost for benefits earned	41		38
Interest cost	71		73
Actuarial loss (gain) (1)	(123)		8
Benefits and expenses paid	(174)		(165)
Federal subsidy on benefits paid	3		3
Plan participant contributions	84		81
Benefit obligation at end of year	$	1,279	$	1,377
Funded Status: (2)
Noncurrent asset	$	1,192	$	1,122
Noncurrent liability	—		—
Net asset at end of year	$	1,192	$	1,122

(1) The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets. The actuarial loss for the year ended December 31, 2023 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations, offset by favorable changes in claims cost and demographic assumptions.

(2) At December 31, 2024 and 2023, 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 $261 million and $296 million as of December 31, 2024, and $275 million and $292 million as of December 31, 2023, respectively.

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)	2024		2023		2022
Service cost for benefits earned (1)	$	396	$	379	$	575
Interest cost	916		913		692
Expected return on plan assets	(1,014)		(981)		(1,189)
Amortization of prior service cost	(3)		(4)		(4)
Amortization of net actuarial loss	1		1		2
Net periodic benefit cost	296		308		76
Less: transfer to regulatory account (2)	39		25		254
Total expense recognized	$	335	$	333	$	330

(1) A portion of service costs are capitalized pursuant to ASC 715.

(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)	2024		2023		2022
Service cost for benefits earned (1)	$	41	$	38	$	62
Interest cost	71		73		53
Expected return on plan assets	(139)		(132)		(130)
Amortization of prior service cost	3		3		7
Amortization of net actuarial gain	(23)		(19)		(40)
Special termination benefits	—		—		22
Net periodic benefit cost	$	(47)	$	(37)	$	(26)

(1) A portion of service costs are capitalized pursuant to ASC 715.

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,
	2024		2023		2022		2024	2023	2022
Discount rate	5.76	%	5.21	%	5.54	%	5.71 - 5.76%	5.18 - 5.22%	5.50 - 5.54%
Rate of future compensation increases	4.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.40	%	6.00	%	6.10	%	3.90 - 7.20%	3.70 - 7.00%	3.70 - 7.30%
Interest crediting rate for cash balance plan	4.41	%	3.86	%	4.19	%	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
	2025		2024		2023		2025		2024		2023
Global equity securities	26	%	26	%	26	%	30	%	29	%	28	%
Absolute return	1	%	1	%	1	%	—	%	—	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	3	%
Fixed-income securities	65	%	65	%	65	%	67	%	68	%	68	%
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, 2024 and 2023.

	Fair Value Measurements
	At December 31,
	2024								2023
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	126	$	47	$	—	$	173	$	565	$	86	$	—	$	651
Global equity securities	1,310		—		—		1,310		1,270		—		—		1,270
Real assets	437		—		—		437		472		—		—		472
Fixed-income securities	2,180		6,367		16		8,563		1,926		6,802		13		8,741
Assets measured at NAV	—		—		—		6,284		—		—		—		6,080
Total	$	4,053	$	6,414	$	16	$	16,767	$	4,233	$	6,888	$	13	$	17,214
PBOP Plans:
Short-term investments	$	27	$	—	$	—	$	27	$	30	$	—	$	—	$	30
Global equity securities	60		—		—		60		66		—		—		66
Real assets	20		—		—		20		32		—		—		32
Fixed-income securities	431		751		1		1,183		422		795		1		1,218
Assets measured at NAV	—		—		—		1,181		—		—		—		1,160
Total	$	538	$	751	$	1	$	2,471	$	550	$	795	$	1	$	2,506
Total plan assets at fair value							$	19,238							$	19,720

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, 2024 and 2023:

(in millions)
For the year ended December 31, 2024	Fixed-Income
Balance at beginning of year	$	13
Actual return on plan assets:
Relating to assets still held at the reporting date	9
Relating to assets sold during the period	(9)
Purchases, issuances, sales, and settlements:
Purchases	14
Settlements	(11)
Balance at end of year	$	16
(in millions)
For the year ended December 31, 2023	Fixed-Income
Balance at beginning of year	$	8
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(1)
Purchases, issuances, sales, and settlements:
Purchases	10
Settlements	(6)
Balance at end of year	$	13

Schedule of Estimated Benefits Expected to be Paid

As of December 31, 2024, 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
2025	969	81	(1)
2026	1,055	84	(1)
2027	1,083	87	(2)
2028	1,109	89	(2)
2029	1,133	91	(2)
2030-2034	5,997	473	(11)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2024

Related Party Transactions [Abstract]

Schedule of Significant Related Party Transactions

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2024		2023		2022
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	66	$	80	$	104
Utility employee benefit due to PG&E Corporation	81		74		85

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WILDFIRE-RELATED CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2024

Commitments and Contingencies Disclosure [Abstract]

Summary of Wildfire-Related Claims

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through December 31, 2024.

Payments (in millions)
2019 Kincade Fire	$	958
2021 Dixie Fire	1,359
2022 Mosquito Fire	18
Total at December 31, 2024	$	2,335

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	458
Accrued Losses	100
Payments	(291)
Balance at December 31, 2024	$	267

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2023.

Loss Accrual (in millions)
Balance at December 31, 2023	$	870
Accrued Losses	325
Payments	(628)
Balance at December 31, 2024	$	567

Loss Accrual (in millions)
Balance at December 31, 2023	$	85
Accrued Losses	—
Payments	(3)
Balance at December 31, 2024	$	82

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2024 are:

Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	527	$	90
FERC TO rates	94		7
WEMA	508		53
Wildfire Fund	925		—
Probable recoveries at December 31, 2024 (1)	$	2,054	$	150

(1) Includes legal costs of $123 million and $50 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2024.

The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2023:

Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2023	$	326	$	63	$	389
Accrued insurance recoveries	1		27		28
Reimbursements	(300)		—		(300)
Balance at December 31, 2024	$	27	$	90	$	117

The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2023:

Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2023	$	600
Accrued Wildfire Fund recoveries	325
Claims paid by Wildfire Fund	(169)
Balance at December 31, 2024	$	756

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OTHER CONTINGENCIES AND COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2024

Commitments and Contingencies Disclosure [Abstract]

Schedule of Environmental Remediation Liability

The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2024		December 31, 2023
Topock natural gas compressor station	$	294	$	276
Hinkley natural gas compressor station	97		104
Former MGP sites owned by the Utility or third parties (1)	782		809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	76		107
Fossil fuel-fired generation facilities and sites (3)	18		19
Total environmental remediation liability	$	1,267	$	1,315

(1) Primarily driven by the following sites: San Francisco Beach Street, 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, 2024:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Natural Gas		Other (1)		Total
2025	$	2,010	$	910	$	443	$	354	$	3,717
2026	1,952		866		348		162		3,328
2027	1,896		800		190		284		3,170
2028	1,875		800		103		141		2,919
2029	1,831		716		92		43		2,682
Thereafter	14,229		2,730		41		5		17,005
Total purchase commitments	$	23,793	$	6,822	$	1,217	$	989	$	32,821

(1) Includes other power purchase agreements and nuclear fuel agreements.

Schedule of Other Commitments

At December 31, 2024, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2025	$	84
2026	44
2027	47
2028	37
2029	34
Thereafter	333
Total minimum payments	$	579

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ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2024 numberOfSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) numberOfSegment facility	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Number of reportable segments | numberOfSegment	1
Restricted cash and cash equivalents	$ 273	$ 297	$ 213
Self insurance contributions	911
Liability insurance coverage, cash and cash equivalents	8
Wildfire self-insurance asset	$ 905	0
Period for probable revenue recovery	24 months
Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Restricted cash and cash equivalents	$ 272	294	$ 213
Wildfire self-insurance asset	$ 905	$ 0
Composite depreciation rate	3.61%	3.56%	3.74%
AFUDC debt recorded	$ 111	$ 82	$ 81
AFUDC equity recorded	$ 184	$ 179	$ 184
Pacific Gas & Electric Co (Utility) | Diablo Canyon
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility	2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Abstract]
Total operating revenues	$ 24,419	$ 24,428	$ 21,680
Electric
Disaggregation of Revenue [Abstract]
Total operating revenues	17,811	17,424	15,060
Natural gas
Disaggregation of Revenue [Abstract]
Total operating revenues	6,608	7,004	6,620
Pacific Gas & Electric Co (Utility)
Disaggregation of Revenue [Abstract]
Total operating revenues	24,419	24,428	21,680
Pacific Gas & Electric Co (Utility) | Electric
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	18,641	15,100	14,832
Regulatory balancing accounts	(830)	2,324	228
Total operating revenues	17,811	17,424	15,060
Pacific Gas & Electric Co (Utility) | Electric | Residential
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	7,504	6,041	6,130
Pacific Gas & Electric Co (Utility) | Electric | Commercial
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	7,201	5,643	5,416
Pacific Gas & Electric Co (Utility) | Electric | Industrial
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	2,065	1,784	1,626
Pacific Gas & Electric Co (Utility) | Electric | Agricultural
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	1,815	1,413	1,830
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	103	83	77
Pacific Gas & Electric Co (Utility) | Electric | Other, net
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	(47)	136	(247)
Pacific Gas & Electric Co (Utility) | Natural gas
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	6,047	6,196	6,055
Regulatory balancing accounts	561	808	565
Total operating revenues	6,608	7,004	6,620
Pacific Gas & Electric Co (Utility) | Natural gas | Residential
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	3,089	3,686	3,353
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	984	1,052	1,005
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	1,815	1,603	1,534
Pacific Gas & Electric Co (Utility) | Natural gas | Other, net
Disaggregation of Revenue [Abstract]
Total revenue from contracts with customers	$ 159	$ (145)	$ 163

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Doubtful Accounts and Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Public Utility, Property, Plant and Equipment [Line Items]
Credit losses	$ 341	$ 636	$ 143
Regulatory assets	15,561	17,189
Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts	7,227	5,660
FERC TO rates
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	85	78
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts	$ 260	$ 507

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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	Dec. 31, 2024	Dec. 31, 2023
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 123,534	$ 115,414
Accumulated depreciation	(35,304)	(33,093)
Net property, plant, and equipment	88,230	82,321
Electricity generating facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	11,420	11,423
Electricity generating facilities | Northern California Wildfire
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 3,000
Electricity generating facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	1 year
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	$ 49,821	45,205
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	$ 18,481	17,562
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	$ 17,213	16,324
Natural gas distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 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	$ 11,117	10,496
Natural gas transmission and storage facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 years
Natural gas transmission and storage facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	68 years
General plant and other
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 10,210	9,165
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
Financing lease
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 814	787
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 4,458	$ 4,452

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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, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability at beginning of year	$ 5,512	$ 5,912
Revision in estimated cash flows	(290)	(585)
Accretion	269	253
Liabilities settled	(47)	(68)
ARO liability at end of year	$ 5,444	$ 5,512

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Public Utility, Property, Plant and Equipment [Line Items]
Asset retirement obligation	$ 5,444	$ 5,512	$ 5,912
Decrease in decommissioning cost	222
Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Nuclear decommissioning obligation accrued	$ 4,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Government Assistance (Details) - USD ($)			12 Months Ended
	Jan. 11, 2024	Oct. 18, 2022	Dec. 31, 2024	Dec. 31, 2023
Public Utility, Property, Plant and Equipment [Line Items]
Government Assistance, Statement of Income or Comprehensive Income [Extensible Enumeration]			Operating and maintenance	Operating and maintenance
Senate Bill 846 | Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount		$ 1,100,000,000
Maximum | Senate Bill 846 | Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount		1,400,000,000
Performance-Based Disbursement
Public Utility, Property, Plant and Equipment [Line Items]
Disbursement		7
Maximum disbursement		$ 300,000,000
Performance-Based Disbursement | Cost of Goods and Services Sold, Electricity
Public Utility, Property, Plant and Equipment [Line Items]
Reimbursement amount				$ 56,000,000
Civil Nuclear Credit Program
Public Utility, Property, Plant and Equipment [Line Items]
Disbursement	$ 1,100,000,000
Civil Nuclear Credit Program | Cost of Goods and Services Sold, Electricity
Public Utility, Property, Plant and Equipment [Line Items]
Reimbursement amount			$ 265,000,000	115,000,000
Civil Nuclear Credit Program | Utilities Operating Expense, Maintenance and Operations
Public Utility, Property, Plant and Equipment [Line Items]
Reimbursement amount			$ 138,000,000	$ 76,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - DWR Loan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Government Assistance, Liability [Roll Forward]
Government Assistance, Liability, Statement of Financial Position [Extensible Enumeration]	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)
DWR Loan
Government Assistance, Liability [Roll Forward]
Beginning balance	$ 98	$ 312	$ 0
Proceeds received	$ 980	$ 0	$ 350
Government Assistance, Liability, Increase, Statement of Financial Position [Extensible Enumeration]	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)	Long-term debt (includes $10.1 billion and $10.5 billion related to VIEs at respective dates)
Ending balance	$ 886	$ 98	$ 312
DWR Loan | Performance-Based Disbursements
Government Assistance, Liability [Roll Forward]
Total deduction	$ (117)	$ (124)	$ (38)
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration]	Operating and maintenance	Operating and maintenance	Operating and maintenance
DWR Loan | Loan forgiveness and other adjustments
Government Assistance, Liability [Roll Forward]
Total deduction	$ (75)	$ (90)	$ 0
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration]	Operating and maintenance	Operating and maintenance	Operating and maintenance

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - VIE (Details) ft² in Thousands	Dec. 31, 2024 USD ($) ft²	Aug. 01, 2024 USD ($)	Dec. 31, 2023 USD ($)	Nov. 30, 2022 USD ($)	Jul. 20, 2022 USD ($)	May 10, 2022 USD ($)	Nov. 12, 2021 USD ($)
Pacific Gas & Electric Co (Utility) | The Lakeside Building
Public Utility, Property, Plant and Equipment [Line Items]
Rentable square feet | ft²	910
Receivables Securitization Program | PG&E AR Facility, LLC (SPV)
Public Utility, Property, Plant and Equipment [Line Items]
Accounts receivable, net	$ 3,200,000,000		$ 2,700,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Long-term debt, gross	0		1,500,000,000
Recovery Bonds | Secured Debt
Public Utility, Property, Plant and Equipment [Line Items]
Long-term debt, gross	10,367,000,000		9,124,000,000
Debt instrument, face amount	3,200,000,000	$ 1,420,000,000	1,800,000,000	$ 983,000,000			$ 860,000,000
SB 901 securitization | Secured Debt
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount	$ 7,200,000,000		$ 7,300,000,000		$ 3,900,000,000	$ 3,600,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Wildfire Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Mar. 31, 2024	Jul. 12, 2019
Public Utility, Property, Plant and Equipment [Line Items]
Litigation liability, current	$ 193
Wildfire Fund asset	301	$ 450
Litigation contribution, net	4,100
Amortization and accretion	383	567	$ 477
Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Wildfire Fund asset	301	450
Amortization and accretion	383	$ 567	$ 477
Other Current Liabilities
Public Utility, Property, Plant and Equipment [Line Items]
Wildfire fund, noncurrent	$ 564
Wildfire Fund Asset
Public Utility, Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life				20 years	15 years

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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, 2024	Dec. 31, 2023
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	$ 25,292	$ 23,075
Unrealized gain on investments	1	8
Net current period other comprehensive income (loss)	(6)	(8)
Ending balance	30,401	25,292
Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Unrealized gain on investments	0	0
Amount attributable to tax, before reclassification	0	0
Net current period other comprehensive income (loss)	(7)	(16)
Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Unrealized gain on investments	0	0
Amount attributable to tax, before reclassification	0	0
Net current period other comprehensive income (loss)	0	0
Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Unrealized gain on investments	1	8
Amount attributable to tax, before reclassification	0	3
Net current period other comprehensive income (loss)	1	8
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(8)	0
Ending balance	(14)	(8)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(28)	(12)
Ending balance	(35)	(28)
Accumulated Other Comprehensive Income (Loss) | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	18	18
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	2	(6)
Ending balance	3	2
Amortization of prior service cost
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	(1)
Amortization of prior service cost | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(3)
Amount attributable to tax, reclassification	1	1
Amortization of prior service cost | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	2
Amount attributable to tax, reclassification	1	1
Amortization of prior service cost | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	0
Amount attributable to tax, reclassification	0	0
Amortization of net actuarial gain
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(239)	(123)
Amounts reclassified from other comprehensive income	(15)	(13)
Amortization of net actuarial gain | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(268)	(196)
Other comprehensive income before reclassifications, tax	104	76
Amounts reclassified from other comprehensive income	1	1
Amount attributable to tax, reclassification	0	0
Amortization of net actuarial gain | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	29	73
Other comprehensive income before reclassifications, tax	11	28
Amounts reclassified from other comprehensive income	(16)	(14)
Amount attributable to tax, reclassification	6	5
Amortization of net actuarial gain | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	0	0
Other comprehensive income before reclassifications, tax	0	0
Amounts reclassified from other comprehensive income	0	0
Amount attributable to tax, reclassification	0	0
Regulatory account transfer
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	231	107
Amounts reclassified from other comprehensive income	16	14
Regulatory account transfer | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	260	180
Other comprehensive income before reclassifications, tax	101	70
Amounts reclassified from other comprehensive income	2	2
Amount attributable to tax, reclassification	1	1
Regulatory account transfer | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(29)	(73)
Other comprehensive income before reclassifications, tax	11	28
Amounts reclassified from other comprehensive income	14	12
Amount attributable to tax, reclassification	5	4
Regulatory account transfer | Customer Credit Trust
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	0	0
Other comprehensive income before reclassifications, tax	0	0
Amounts reclassified from other comprehensive income	0	0
Amount attributable to tax, reclassification	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Leases (Details) ft² in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($) ft²	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jun. 30, 2025 USD ($)	Jul. 11, 2024 USD ($)	Jul. 11, 2023 USD ($)	Oct. 23, 2020 USD ($) ft²
Lessee, Lease, Description [Line Items]
Cash payments for financing lease		$ 315	$ 142
Financing lease, right of use asset, net		807	787
Accumulated amortization		282	108
Leasehold improvements		136	218
Leasehold incentives		51	134
Financing lease liabilities		577	259
Financing lease liabilities		$ 4	$ 554
Weighted average remaining lease term, finance lease		6 months	1 year 7 months 6 days
Weighted average discount rate, finance lease		6.20%	6.50%
Lease payments		$ 1,600	$ 1,900	$ 2,300
Weighted average remaining lease term. operating lease		7 years 6 months	8 years 2 months 12 days
Weighted average discount rate, operating lease		6.50%	6.40%
Pacific Gas & Electric Co (Utility)
Lessee, Lease, Description [Line Items]
Financing lease liabilities		$ 577	$ 259
Financing lease liabilities		$ 4	$ 554
Pacific Gas & Electric Co (Utility) | Forecast
Lessee, Lease, Description [Line Items]
Cash payments for financing lease	$ 591
Oakland Headquarters Lease | Pacific Gas & Electric Co (Utility)
Lessee, Lease, Description [Line Items]
Rentable square feet | ft²		715						910
Lease, option payment letter of credit								$ 75
Lease, security letter of credit								$ 75
Purchase price							$ 906
Purchase price, deposits						$ 250	$ 150
Oakland Headquarters Lease | Pacific Gas & Electric Co (Utility) | Forecast
Lessee, Lease, Description [Line Items]
Purchase price, deposits					$ 506
Purchase price, deposits credit					$ 172
All But Vehicle Lease Agreements
Lessee, Lease, Description [Line Items]
Financing lease liabilities		$ 575

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Financing lease fixed cost:
Amortization of ROU assets	$ 274	$ 115
Interest on lease liabilities	42	27
Financing lease variable cost	9	3
Total financing lease costs	325	145
Operating Lease Costs [Abstract]
Operating lease fixed cost	116	269	$ 500
Operating lease variable cost	1,524	1,632	1,829
Total operating lease costs	$ 1,640	$ 1,901	$ 2,329

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Future Expected Operating Lease Payments
2025	$ 116
2026	112
2027	110
2028	97
2029	62
Thereafter	195
Total lease payments	692
Less imputed interest	(173)
Total	$ 519

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Jun. 30, 2022	Feb. 28, 2022
Regulatory Assets [Line Items]
Regulatory assets	$ 15,561	$ 17,189
Customer Harm Threshold, post-emergence transaction, recovery bonds issued				$ 7,500
Initial shareholder contribution	2,000
Pension benefits
Regulatory Assets [Line Items]
Regulatory assets	673	348
Environmental compliance costs
Regulatory Assets [Line Items]
Regulatory assets	$ 1,172	1,218
Recovery Period	32 years
Price risk management
Regulatory Assets [Line Items]
Regulatory assets	$ 167	160
Recovery Period	15 years 6 months
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Regulatory assets	$ 742	1,074
Catastrophic event memorandum account | COVID-19
Regulatory Assets [Line Items]
Regulatory assets	1	43
Wildfire-related accounts
Regulatory Assets [Line Items]
Regulatory assets	$ 1,697	2,915
Wildfire-related accounts | Maximum
Regulatory Assets [Line Items]
Recovery Period	3 years
Wildfire-related accounts | Minimum
Regulatory Assets [Line Items]
Recovery Period	1 year
Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	$ 4,771	3,543
Financing costs
Regulatory Assets [Line Items]
Regulatory assets	216	196
SB 901 securitization
Regulatory Assets [Line Items]
Regulatory assets	$ 5,194	5,249	$ 5,500
Recovery Period	28 years
General rate case memorandum accounts
Regulatory Assets [Line Items]
Regulatory assets	$ 95	1,291
Other
Regulatory Assets [Line Items]
Regulatory assets	$ 834	$ 1,195

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Jun. 30, 2022
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	$ 19,417	$ 19,444
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	306
Authorized amount of shareholder tax benefits to be returned	7,590
Pacific Gas & Electric Co (Utility)
Regulatory Liabilities [Line Items]
Current regulatory liabilities	1,200	1,200
Total noncurrent regulatory liabilities	19,417	19,444
Federal Energy Regulatory Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	273
California Public Utilities Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers	33
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	8,943	8,191
Public purpose programs
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	1,112	1,238
Employee benefit plans
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	1,088	1,032
Transmission tower wireless licenses
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	306	384
SFGO sale
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	79	185
SB 901 securitization
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	6,295	6,628	$ 5,540
Wildfire self-insurance
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	804	407
Other
Regulatory Liabilities [Line Items]
Total noncurrent regulatory liabilities	$ 790	$ 1,379

XML

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Interest income/expense	$ 604	$ 606	$ 162
Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Interest income/expense	323	257	81
Total regulatory balancing accounts	3,169	1,669
Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Interest income/expense	537	547	$ 153
Total regulatory balancing accounts	7,227	5,660
Electric distribution | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	1,591	1,092
Electric transmission | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	883	200
Electric transmission | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	117	99
Gas distribution and transmission | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	72	224
Gas distribution and transmission | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	387	144
Energy procurement | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	329	77
Energy procurement | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	1,066	1,002
Public purpose programs | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	882	299
Public purpose programs | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	162	137
SFGO sale | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	93	79
Wildfire-related accounts | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	337	125
Wildfire-related accounts | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	979	568
Insurance premium costs | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	38	227
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	260	507
Catastrophic event memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	500	413
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	1,113	1,097
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	23	216
Other | Regulatory Balancing Accounts Payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	550	449
Other | Regulatory Balancing Accounts Receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 1,014	$ 374

XML

DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)	Jul. 25, 2024	Dec. 31, 2024	Dec. 31, 2023
Utility revolving credit facility
Debt [Line Items]
Maximum Facility Limit		$ 6,400,000,000
Loans Outstanding		0
Letters of Credit Outstanding		(633,000,000)
Facility Availability		5,767,000,000
Utility revolving credit facility | PG&E Corporation revolving credit facility
Debt [Line Items]
Maximum Facility Limit		500,000,000
Loans Outstanding		0
Letters of Credit Outstanding		0
Facility Availability		500,000,000
Extension option, term	1 year
Utility revolving credit facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Maximum Facility Limit	$ 4,196,000,000	4,400,000,000
Loans Outstanding		0
Letters of Credit Outstanding		(633,000,000)
Facility Availability	$ 204,000,000	3,767,000,000
Extension option, term	1 year
Letter of credit sublimit		2,000,000,000
Utility Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Maximum Facility Limit		1,500,000,000
Loans Outstanding		0	$ (1,500,000,000)
Letters of Credit Outstanding		0
Facility Availability		$ 1,500,000,000

XML

DEBT (Narrative) (Details)						12 Months Ended
	Nov. 15, 2024 USD ($)	Sep. 11, 2024 USD ($)	Jul. 25, 2024 USD ($)	Apr. 16, 2024 USD ($)	Dec. 04, 2023 USD ($) day $ / shares	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Sep. 05, 2024 USD ($)	Aug. 01, 2024 USD ($)	Feb. 28, 2024 USD ($)	Aug. 10, 2023 USD ($)
Debt [Line Items]
Write-off of deferred debt issuance costs						$ 9,000,000
Debt financial instrument						53,569,000,000	$ 50,975,000,000
Repayments of long-term debt						800,000,000	3,075,000,000	$ 5,968,000,000
PG&E Corporation
Debt [Line Items]
Repayments of long-term debt						0	0	28,000,000
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Capital expenditures for future recovery												$ 1,380,000,000
Repayments of long-term debt						$ 800,000,000	3,075,000,000	$ 5,941,000,000
2 Year Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount				$ 400,000,000
Interest rate						6.60%
364-Day 2023 Tranche Loans | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount				125,000,000
364 Day 2024 Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount				$ 525,000,000
364 Day 2024 Term Loan | Pacific Gas & Electric Co (Utility) | SOFR
Debt [Line Items]
Credit spread adjustment				0.10%
Basis spread on variable rate				1.375%
364 Day 2024 Term Loan | Pacific Gas & Electric Co (Utility) | Base Rate
Debt [Line Items]
Basis spread on variable rate				0.375%
Term Loan
Debt [Line Items]
Long-term debt, gross		$ 500,000,000
Term Loan | PG&E Corporation
Debt [Line Items]
Repayments of long-term debt					$ 2,150,000,000
Utility revolving credit facility
Debt [Line Items]
Maximum facility limit						$ 6,400,000,000
Remaining borrowings capacity						5,767,000,000
Long-term debt, gross						0
Utility revolving credit facility | PG&E Corporation
Debt [Line Items]
Maximum facility limit						500,000,000
Extension option, term			1 year
Remaining borrowings capacity						500,000,000
Long-term debt, gross						0
Utility revolving credit facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Maximum facility limit			$ 4,196,000,000			4,400,000,000
Extension option, term			1 year
Remaining borrowings capacity			$ 204,000,000			3,767,000,000
Long-term debt, gross						0
Series 2024-A Senior Secured Recovery Bonds | Pacific Gas & Electric Co (Utility) | Secured Debt
Debt [Line Items]
Debt instrument, face amount										$ 1,420,000,000
Recovery Bonds Tranche One | Pacific Gas & Electric Co (Utility) | Secured Debt
Debt [Line Items]
Debt instrument, face amount										$ 300,000,000
Interest rate										4.838%
Recovery Bonds Tranche Two | Pacific Gas & Electric Co (Utility) | Secured Debt
Debt [Line Items]
Debt instrument, face amount										$ 373,000,000
Interest rate										5.231%
Recovery Bonds Tranche Three | Pacific Gas & Electric Co (Utility) | Secured Debt
Debt [Line Items]
Debt instrument, face amount										$ 746,000,000
Interest rate										5.529%
First Mortgage Bonds Due 2025 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount									$ 1,000,000,000
First Mortgage Bonds Due 2029 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount											$ 850,000,000
Interest rate											5.55%
Long-term debt, gross						$ 2,100,000,000	1,250,000,000
First Mortgage Bonds Due 2029 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Interest rate						4.20%
First Mortgage Bonds Due 2034 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount											$ 1,100,000,000
Interest rate											5.80%
Long-term debt, gross						$ 1,900,000,000	800,000,000
First Mortgage Bonds Due 2034 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Interest rate						5.80%
First Mortgage Bonds Due 2053 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount											$ 300,000,000
Interest rate											6.75%
First Mortgage Bonds Due 2054 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount									$ 750,000,000
Interest rate									5.90%
Junior Subordinated Notes Due 2055
Debt [Line Items]
Debt instrument, face amount	$ 500,000,000	$ 1,000,000,000
Basis spread on variable rate	3.883%	3.883%
Interest rate	7.375%	7.375%
Junior Subordinated Notes Due 2055 | Minimum
Debt [Line Items]
Basis spread on variable rate	7.375%	7.375%
Junior Subordinated Notes Due 2055 | PG&E Corporation
Debt [Line Items]
Interest rate						7.38%
Long-term debt, gross						$ 1,500,000,000	0
Convertible Notes Due 2027 | PG&E Corporation
Debt [Line Items]
Interest rate						4.25%
Long-term debt, gross						$ 2,150,000,000	2,150,000,000
Convertible Notes Due 2027 | PG&E Corporation | Secured Debt
Debt [Line Items]
Debt instrument, face amount					$ 2,150,000,000
Interest rate					4.25%
Debt financial instrument					$ 2,120,000,000	2,130,000,000	2,120,000,000
Conversion rate					0.0431416
Conversion price | $ / shares					$ 23.18
Debt instrument, redemption price, percentage					100.00%
Debt issuance costs						20,000,000	(27,000,000)
Interest expense						$ 98,000,000	$ 7,000,000
Convertible Notes Due 2027 | PG&E Corporation | Secured Debt | Debt Conversion Terms One
Debt [Line Items]
Threshold trading days | day					20
Threshold consecutive trading days | day					30
Threshold percentage of stock price					130.00%
Convertible Notes Due 2027 | PG&E Corporation | Secured Debt | Debt Conversion Terms Two
Debt [Line Items]
Threshold trading days | day					5
Threshold consecutive trading days | day					10
Threshold percentage of stock price					90.00%

XML

DEBT (Schedule of Long-term Debt) (Details) - USD ($)	Dec. 31, 2024	Nov. 15, 2024	Sep. 11, 2024	Feb. 28, 2024	Dec. 31, 2023	Dec. 04, 2023
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	$ (2,146,000,000)				$ (1,376,000,000)
Long-term debt, net	53,569,000,000				50,975,000,000
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(2,146,000,000)				(1,376,000,000)
New Debt | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	0				(400,000,000)
Long-term debt, net	47,958,000,000				46,376,000,000
New Debt | PG&E Corporation
Debt [Line Items]
Unamortized discount, premium and debt issuance costs, net	(39,000,000)				(51,000,000)
Long-term debt, net	$ 5,611,000,000				4,599,000,000
Term Loan B, Stated Maturity 2027 | PG&E Corporation
Debt [Line Items]
Stated interest rate	7.85%
Long-term debt, gross	$ 0				500,000,000
Convertible Notes Due 2027 | PG&E Corporation
Debt [Line Items]
Stated interest rate	4.25%
Long-term debt, gross	$ 2,150,000,000				2,150,000,000
Convertible Notes Due 2027 | PG&E Corporation | Secured Debt
Debt [Line Items]
Stated interest rate						4.25%
Long-term debt, net	$ 2,130,000,000				2,120,000,000	$ 2,120,000,000
Senior Notes Due 2028 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.00%
Long-term debt, gross	$ 1,000,000,000				1,000,000,000
Senior Notes Due 2030 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.25%
Long-term debt, gross	$ 1,000,000,000				1,000,000,000
Junior Subordinated Notes Due 2055
Debt [Line Items]
Stated interest rate		7.375%	7.375%
Junior Subordinated Notes Due 2055 | PG&E Corporation
Debt [Line Items]
Stated interest rate	7.38%
Long-term debt, gross	$ 1,500,000,000				0
First Mortgage Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of unamortized discount and debt issuance costs	(1,924,000,000)				(800,000,000)
Unamortized discount, premium and debt issuance costs, net	(226,000,000)				(246,000,000)
Long-term debt, net	36,927,000,000				35,831,000,000
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 0				800,000,000
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.40%
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	$ 1,925,000,000				1,925,000,000
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	$ 2,551,000,000				2,551,000,000
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	$ 3,000,000,000				3,000,000,000
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	$ 1,975,000,000				1,975,000,000
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 Due 2029 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate				5.55%
Long-term debt, gross	$ 2,100,000,000				1,250,000,000
First Mortgage Bonds Due 2029 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.20%
First Mortgage Bonds Due 2029 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	6.10%
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 3,100,000,000				3,100,000,000
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.55%
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 3,000,000,000				3,000,000,000
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]
Long-term debt, gross	$ 1,050,000,000				1,050,000,000
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 Due 2033 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,900,000,000				1,900,000,000
First Mortgage Bonds Due 2033 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	6.15%
First Mortgage Bonds Due 2033 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	6.40%
First Mortgage Bonds Due 2034 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate				5.80%
Long-term debt, gross	$ 1,900,000,000				800,000,000
First Mortgage Bonds Due 2034 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	5.80%
First Mortgage Bonds Due 2034 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	6.95%
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,951,000,000				2,951,000,000
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	$ 700,000,000				700,000,000
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	$ 750,000,000				750,000,000
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]
Long-term debt, gross	$ 375,000,000				375,000,000
First Mortgage Bonds, Stated Maturity 2043 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.60%
First Mortgage Bonds, Stated Maturity 2044 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.75%
Long-term debt, gross	$ 675,000,000				675,000,000
First Mortgage Bonds, Stated Maturity 2045 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.30%
Long-term debt, gross	$ 600,000,000				600,000,000
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,050,000,000				1,050,000,000
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]
Long-term debt, gross	$ 850,000,000				850,000,000
First Mortgage Bonds, Stated Maturity 2047 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.95%
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 5,025,000,000				5,025,000,000
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]
Long-term debt, gross	$ 550,000,000				550,000,000
First Mortgage Bonds, Stated Maturity 2052 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	5.25%
First Mortgage Bonds, Stated Maturity 2053 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,300,000,000				2,000,000,000
First Mortgage Bonds, Stated Maturity 2053 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	6.70%
First Mortgage Bonds, Stated Maturity 2053 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	6.75%
First Mortgage Bonds, Stated Maturity 2054 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 750,000,000				0
First Mortgage Bonds, Stated Maturity 2054 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	5.90%
Recovery Bonds | Secured Debt
Debt [Line Items]
Long-term debt, gross	$ 10,367,000,000				9,124,000,000
Less: current portion, net of unamortized discount and debt issuance costs	(222,000,000)				(176,000,000)
DWR Loan
Debt [Line Items]
Long-term debt, net	$ 886,000,000				98,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	6.75%
Long-term debt, gross	$ 0				1,500,000,000
Long-term debt, net	$ 0				1,499,000,000
2 Year Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	6.60%
Term Loan	$ 0				$ 400,000,000

XML

DEBT (Schedule of Contractual Repayment Schedule) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Debt [Line Items]
Total consolidated debt	$ 55,094
AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	3,160
SB 901 obligations
Debt [Line Items]
Fixed rate obligations	$ 7,207
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	4.44%
Fixed rate obligations	$ 39,077
PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.39%
Fixed rate obligations	$ 5,650
2025
Debt [Line Items]
Total consolidated debt	2,148
2025 | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	88
2025 | SB 901 obligations
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
2025 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2026
Debt [Line Items]
Total consolidated debt	2,772
2026 | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	81
2026 | SB 901 obligations
Debt [Line Items]
Fixed rate obligations	$ 140
2026 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.10%
Fixed rate obligations	$ 2,551
2026 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2027
Debt [Line Items]
Total consolidated debt	5,380
2027 | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	84
2027 | SB 901 obligations
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
2027 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	4.25%
Fixed rate obligations	$ 2,150
2028
Debt [Line Items]
Total consolidated debt	3,215
2028 | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	88
2028 | SB 901 obligations
Debt [Line Items]
Fixed rate obligations	$ 152
2028 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.58%
Fixed rate obligations	$ 1,975
2028 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.00%
Fixed rate obligations	$ 1,000
2029
Debt [Line Items]
Total consolidated debt	2,350
2029 | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	91
2029 | SB 901 obligations
Debt [Line Items]
Fixed rate obligations	$ 159
2029 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	5.52%
Fixed rate obligations	$ 2,100
2029 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Thereafter
Debt [Line Items]
Total consolidated debt	39,229
Thereafter | AB 1054 obligations
Debt [Line Items]
Fixed rate obligations	2,728
Thereafter | SB 901 obligations
Debt [Line Items]
Fixed rate obligations	$ 6,475
Thereafter | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	4.72%
Fixed rate obligations	$ 27,526
Thereafter | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	6.53%
Fixed rate obligations	$ 2,500

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Mar. 28, 2024	Jun. 30, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt [Line Items]
Regulatory assets			$ 15,561	$ 17,189
Initial shareholder contribution			2,000
Regulatory liabilities			19,417	19,444
SB 901 securitization charges, net			33	1,267	$ 608
SB 901 securitization
Debt [Line Items]
Regulatory liabilities		$ 5,540	6,295	6,628
SB 901 securitization | Secured Debt
Debt [Line Items]
Initial shareholder contribution	$ 350	2,000	650		$ 1,000
Additional contributions funded by tax benefits			7,590
Amortization of regulatory asset and liability			328	322
SB 901 securitization charges, net				1,300
Nothern California Wild Fire
Debt [Line Items]
Loss contingency, costs incurred		7,500
SB 901 securitization
Debt [Line Items]
Regulatory assets		$ 5,500	$ 5,194	$ 5,249

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SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Financial Statement Impact) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
SB 901 securitization regulatory asset
Beginning balance	$ 17,189
Ending balance	15,561	$ 17,189
SB 901 securitization regulatory liability
Beginning balance	(19,444)
Ending balance	(19,417)	(19,444)
SB 901 Securitization Inception
SB 901 securitization regulatory liability
Beginning balance	(6,628)	(5,800)
Amortization	383	451
Additions	(50)	(1,279)
Ending balance	(6,295)	(6,628)
Increase in regulatory liabilities	50	1,279
SB 901 Securitization Inception | Customer credit trust
SB 901 securitization regulatory liability
Additions	(16)	(12)
Increase in regulatory liabilities	16	12
SB 901 Securitization Inception
SB 901 securitization regulatory asset
Beginning balance	5,249	5,378
Amortization	(55)	(129)
Ending balance	$ 5,194	$ 5,249

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COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($)						3 Months Ended				12 Months Ended
	Dec. 04, 2024	Nov. 29, 2024	Sep. 19, 2024	May 16, 2024	Feb. 13, 2024	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Feb. 05, 2025	Jul. 08, 2021
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)						2,193,573,536				2,193,573,536	2,133,597,758
Common stock issued, net										$ 1,128,000,000	$ (2,517,000,000)	$ (2,337,000,000)
Investment plan, term										5 years
Entity Common Stock, Shares Outstanding (in shares)													2,671,320,389
Common stock dividends declared										$ 120,000,000	21,000,000
Preferred stock dividend requirement										$ 37,000,000	$ 14,000,000	$ 13,000,000
Shares available for LTIP award (in shares)						55,900,800				55,900,800
Granted (in dollars per share)										$ 16.74	$ 15.70	$ 11.40
Total fair value										$ 62,000,000	$ 64,000,000	$ 46,000,000
Total unrecognized compensation costs										$ 90,000,000
Remaining weighted average period										1 year 6 months 7 days
Over-Allotment Option
Schedule of Capitalization, Equity [Line Items]
Common stock issued, net	$ 1,130,000,000
Pacific Gas & Electric Co (Utility)
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)						800,000,000				800,000,000	800,000,000
Entity Common Stock, Shares Outstanding (in shares)													264,374,809
Common stock dividends declared		$ 575,000,000	$ 500,000,000	$ 500,000,000	$ 450,000,000
Preferred stock dividend requirement		3,500,000	3,500,000	3,500,000	3,500,000					$ 14,000,000	$ 14,000,000	$ 14,000,000
Employee Stock Option
Schedule of Capitalization, Equity [Line Items]
Granted (in shares)										0	0
Weighted-average period										1 year 2 months 1 day
Restricted stock units
Schedule of Capitalization, Equity [Line Items]
Award vesting period										3 years
Tax detriment										$ 21,000,000
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)										$ 16.94	$ 13.39	$ 13.44
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized										$ 48,000,000
2014 LTIP, Amended
Schedule of Capitalization, Equity [Line Items]
Number of shares issued for LTIP, maximum (in shares)						91,000,000				91,000,000
2014 LTIP | Employee Stock Option
Schedule of Capitalization, Equity [Line Items]
Term of award										10 years
Award vesting period										3 years
Total unrecognized compensation costs						$ 0				$ 0
Granted (in shares)										0
PG&E Corporation
Schedule of Capitalization, Equity [Line Items]
Common stock dividend declared (in dollars per share)						$ 0.025	$ 0.01	$ 0.01	$ 0.01
Preferred stock dividend requirement		$ 55,000,000	$ 21,000,000	$ 21,000,000	$ 21,000,000
PG&E Corporation | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding, adjusted (in shares)													2,193,576,799
PG&E Corporation | Minimum
Schedule of Capitalization, Equity [Line Items]
Percentage of equity security ownership with board of director approval						4.75%				4.75%				4.75%
Pacific Gas & Electric Co (Utility)
Schedule of Capitalization, Equity [Line Items]
Common stock issued, net (in shares)	55,961,070

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COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 98	$ 91	$ 115
Total compensation expense (after-tax)	71	65	83
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	67	64	60
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 31	$ 27	$ 55

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COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Employee Stock Option - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Number of Stock Options
Granted (in shares)	0	0
2014 LTIP
Number of Stock Options
Outstanding, beginning of period (in shares)	1,396,261
Granted (in shares)	0
Exercised (in shares)	0
Forfeited or expired (in shares)	(652,298)
Outstanding, end of period (in shares)	743,963	1,396,261
Vested or expected to vest (in shares)	743,963
Exercisable (in shares)	743,963
Weighted Average Grant- Date Fair Value
Outstanding, beginning of period (in dollars per share)	$ 8.2
Forfeited or expired (in dollars per share)	6.89
Outstanding, end of period (in dollars per share)	10.23	$ 8.2
Vested or expected to vest (in dollars per share)	10.23
Exercisable (in dollars per share)	$ 10.23
Weighted Average Remaining Contractual Term (Years)
Outstanding	2 years 6 months 29 days
Expected to vest	2 years 6 months 29 days
Exercisable	2 years 6 months 29 days

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COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Number of Restricted Stock Units
Nonvested, beginning balance (in shares)	9,268,425
Granted (in shares)	5,273,850
Vested (in shares)	(4,922,000)
Forfeited (in shares)	(196,693)
Nonvested, ending balance (in shares)	9,423,582	9,268,425
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 13.29
Granted (in dollars per share)	16.74	$ 15.70	$ 11.40
Vested (in dollars per share)	12.62
Forfeited (in dollars per share)	15.27
Nonvested, ending balance (in dollars per share)	$ 15.52	$ 13.29

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COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Number of Restricted Stock Units
Nonvested , beginning balance (in shares)	6,602,292
Granted (in shares)	2,714,196
Vested (in shares)	(1,779,695)
Forfeited (in shares)	(356,587)
Nonvested, ending balance (in shares)	7,180,206	6,602,292
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 14.06
Granted (in dollars per share)	16.94	$ 13.39	$ 13.44
Vested (in dollars per share)	10.70
Forfeited (in dollars per share)	13.07
Nonvested, ending balance (in dollars per share)	$ 15.52	$ 14.06

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PREFERRED STOCK (Details)							3 Months Ended	12 Months Ended
	May 15, 2025 USD ($)	Dec. 05, 2024 USD ($) $ / shares shares	Nov. 29, 2024 USD ($)	Sep. 19, 2024 USD ($)	May 16, 2024 USD ($)	Feb. 13, 2024 USD ($)	Dec. 31, 2024 USD ($) $ / shares shares	Dec. 31, 2024 USD ($) $ / shares shares	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2022 USD ($)	Jan. 31, 2022 USD ($)
Preferred Stock [Line Items]
Preferred Stock issued, net								$ 1,579,000,000
Investment plan, term								5 years
Cumulative and unpaid dividends											$ 59,000,000
Preferred stock dividend requirement								$ 37,000,000	$ 14,000,000	$ 13,000,000
6.000% Series A Mandatory Convertible Preferred Stock, no par value
Preferred Stock [Line Items]
Preferred stock, shares issued (in shares) | shares		32,200,000
Preferred stock interest rate		6.00%
Preferred stock, par value (in dollars per share) | $ / shares		$ 50.00
Preferred Stock issued, net		$ 1,600,000,000
Dividends accumulated, amount per share (in dollars per shares)		$ 0.7167
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Forecast
Preferred Stock [Line Items]
Dividends accumulated, amount per share (in dollars per shares)	$ 0.75
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Minimum
Preferred Stock [Line Items]
Preferred stock, convertible, conversion ratio		1.9465
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Maximum
Preferred Stock [Line Items]
Preferred stock, convertible, conversion ratio		2.4331
Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock dividends paid								14,000,000	14,000,000	70,000,000
Preferred stock dividend requirement			$ 3,500,000	$ 3,500,000	$ 3,500,000	$ 3,500,000		$ 14,000,000	$ 14,000,000	$ 14,000,000
Pacific Gas & Electric Co (Utility) | Minimum
Preferred Stock [Line Items]
Redemption price (in dollars per share) | $ / shares							$ 25.75	$ 25.75	$ 25.75
Pacific Gas & Electric Co (Utility) | Maximum
Preferred Stock [Line Items]
Redemption price (in dollars per share) | $ / shares							$ 27.25	$ 27.25	$ 27.25
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock
Preferred Stock [Line Items]
Nonredeemable preferred stock outstanding							$ 145,000,000	$ 145,000,000	$ 145,000,000
Preferred stock dividends per share, low range (in dollars per share) | $ / shares								$ 1.25
Preferred stock dividends per share, high range (in dollars per share) | $ / shares								$ 1.50
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate								5.00%
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate								6.00%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock
Preferred Stock [Line Items]
Redeemable preferred stock outstanding							$ 113,000,000	$ 113,000,000	$ 113,000,000
Preferred stock dividends per share, low range (in dollars per share) | $ / shares								$ 1.09
Preferred stock dividends per share, high range (in dollars per share) | $ / shares								$ 1.25
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate									4.36%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate									5.00%
PG&E Corporation
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares) | shares							400,000,000	400,000,000
Preferred stock dividend requirement			$ 55,000,000	$ 21,000,000	$ 21,000,000	$ 21,000,000
PG&E Corporation | 6.000% Series A Mandatory Convertible Preferred Stock, no par value
Preferred Stock [Line Items]
Preferred stock, dividends declared (in dollars per share) | $ / shares							$ 0.7167
$25 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares) | shares							75,000,000	75,000,000
Preferred stock, par value (in dollars per share) | $ / shares							$ 25	$ 25
$100 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares) | shares							10,000,000	10,000,000
Preferred stock, par value (in dollars per share) | $ / shares							$ 100	$ 100
Preferred stock, shares outstanding (in shares) | shares							0	0

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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, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Income (loss) available for common shareholders, basic	$ 2,475	$ 2,242	$ 1,800
Income (loss) available for common shareholders diluted	$ 2,475	$ 2,242	$ 1,800
Weighted average common shares outstanding, basic (in shares)	2,141,000,000	2,064,000,000	1,987,000,000
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	6,000,000	6,000,000	8,000,000
Equity Units (in shares)	0	68,000,000	137,000,000
Weighted average common share outstanding, diluted (in shares)	2,147,000,000	2,138,000,000	2,132,000,000
Total earnings (loss) per common share, diluted (in dollars per share)	$ 1.15	$ 1.05	$ 0.84
PG&E Corporation
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Income (loss) available for common shareholders, basic	$ 2,475	$ 2,242	$ 1,743
Income (loss) available for common shareholders diluted	$ 2,475	$ 2,242	$ 1,743
Weighted average common shares outstanding, basic (in shares)	2,141,000,000	2,064,000,000	2,235,000,000
Add incremental shares from assumed conversions:
Weighted average common share outstanding, diluted (in shares)	2,147,000,000	2,138,000,000	2,380,000,000
Total earnings (loss) per common share, diluted (in dollars per share)	$ 1.15	$ 1.05	$ 0.73
Number of shares sold (in shares)	477,743,590	477,743,590	477,743,590

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INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current:
Federal	$ 2	$ (1)	$ (1)
State	(78)	0	0
Deferred:
Federal	(137)	(1,047)	(943)
State	15	(507)	(389)
Tax credits	(2)	(2)	(5)
Income tax benefit	(200)	(1,557)	(1,338)
Pacific Gas & Electric Co (Utility)
Current:
Federal	2	(1)	(1)
State	(78)	0	0
Deferred:
Federal	(72)	(981)	(852)
State	45	(477)	(348)
Tax credits	(2)	(2)	(5)
Income tax benefit	$ (105)	$ (1,461)	$ (1,206)

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INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Pacific Gas & Electric Co (Utility)
Deferred income tax assets:
Tax carryforwards	$ 8,955	$ 8,740
Compensation	86	82
GHG allowance	471	361
Wildfire-related claims	295	1,069
Operating lease liability	78	142
Transmission tower wireless licenses	251	250
Bad debt	127	134
Other	137	109
Total deferred income tax assets	10,400	10,887
Deferred income tax liabilities:
Property-related basis differences	11,009	10,047
Regulatory balancing accounts	878	1,433
Debt financing costs	390	428
Operating lease ROU asset	78	142
Income tax regulatory asset	1,335	991
Environmental reserve	248	200
Other	94	82
Total deferred income tax liabilities	14,032	13,323
Total net deferred income tax liabilities	3,632	2,436
PG&E Corporation
Deferred income tax assets:
Tax carryforwards	9,429	9,132
Compensation	171	145
GHG allowance	471	361
Wildfire-related claims	295	1,069
Operating lease liability	78	142
Transmission tower wireless licenses	251	250
Bad debt	127	134
Other	140	130
Total deferred income tax assets	10,962	11,363
Deferred income tax liabilities:
Property-related basis differences	11,021	10,058
Regulatory balancing accounts	878	1,433
Debt financing costs	390	428
Operating lease ROU asset	78	142
Income tax regulatory asset	1,335	991
Environmental reserve	248	200
Other	94	91
Total deferred income tax liabilities	14,044	13,343
Total net deferred income tax liabilities	$ 3,082	$ 1,980

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INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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)	(0.80%)	(34.40%)	(26.90%)
Effect of regulatory treatment of fixed asset differences	(24.70%)	(40.10%)	(49.20%)
Tax credits	(0.70%)	(2.20%)	(1.30%)
Fire Victim Trust	0.00%	(80.20%)	(64.00%)
Other, net	1.20%	1.10%	2.20%
Effective tax rate	(4.00%)	(134.80%)	(118.20%)
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)	(2.00%)	(57.90%)	(75.80%)
Effect of regulatory treatment of fixed asset differences	(28.30%)	(63.40%)	(123.80%)
Tax credits	(0.70%)	(2.20%)	(3.20%)
Fire Victim Trust	0.00%	(126.90%)	(160.90%)
Other, net	1.20%	2.20%	12.90%
Effective tax rate	(8.80%)	(227.20%)	(329.80%)

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INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pacific Gas & Electric Co (Utility)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	$ 616	$ 570	$ 498
Additions for tax position taken during a prior year	0	1	0
Reductions for tax position taken during a prior year	(257)	0	(1)
Additions for tax position taken during the current year	95	45	73
Settlements	0	0	0
Balance, end of period	454	616	570
PG&E Corporation
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	616	570	498
Additions for tax position taken during a prior year	0	1	0
Reductions for tax position taken during a prior year	(257)	0	(1)
Additions for tax position taken during the current year	95	45	73
Settlements	0	0	0
Balance, end of period	$ 454	$ 616	$ 570

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INCOME TAXES (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
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	$ 106
Income tax deduction, repair costs	850
Income tax deduction, customer bill credits	400
Pacific Gas & Electric Co (Utility)
Investments, Owned, Federal Income Tax Note [Line Items]
Income tax deduction, accrued amount	$ 70

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INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	$ 125
Federal | Pre-2018
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	3,369
Federal | Post-2017
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	30,288
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	34,901
Tax credit carryforward	$ 146

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DERIVATIVES (Narrative) (Details)	Dec. 31, 2024	Dec. 31, 2023
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, 2024 MMBTU MWh	Dec. 31, 2023 MMBTU MWh
Forwards, futures, and swaps | Natural Gas
Derivative [Line Items]
Contract Volume	179,257,247	196,063,296
Forwards, futures, and swaps | Electricity (MWh)
Derivative [Line Items]
Contract Volume | MWh	8,576,078	9,169,967
Options | Natural Gas
Derivative [Line Items]
Contract Volume	37,717,500	30,695,000
Options | Electricity (MWh)
Derivative [Line Items]
Contract Volume	1,663,200	92,400
Congestion Revenue Rights | Electricity (MWh)
Derivative [Line Items]
Contract Volume | MWh	123,040,895	170,465,674

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DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Contract - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance, Asset	$ 100	$ 82
Netting, Asset	0	0
Cash Collateral	0	96
Total Derivative Balance, Asset	100	178
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance, Asset	186	134
Netting, Asset	(16)	(8)
Cash Collateral	0	50
Total Derivative Balance, Asset	170	176
Noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance, Asset	233	280
Netting, Asset	0	0
Cash Collateral	0	0
Total Derivative Balance, Asset	233	280
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance, Liabilities	(152)	(172)
Netting, Liabilities	16	8
Cash Collateral	0	46
Total Derivative Balance, Liabilities	(136)	(118)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance, Liabilities	(167)	(160)
Netting, Liabilities	0	0
Cash Collateral	0	0
Total Derivative Balance, Liabilities	$ (167)	$ (160)

XML

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Assets:
Price risk management instruments, netting	$ (16)	$ 42
Price risk management instruments, assets	403	456
TOTAL ASSETS	7,404	5,501
Liabilities:
Price risk management instruments, netting	(16)	(54)
TOTAL LIABILITIES	303	278
Amount primarily related to deferred taxes on appreciation of investment value	747	717
Short-term investments
Assets:
Short-term investments	826	203
PERS
Assets:
Short-term investments	905
TOTAL ASSETS	905
Nuclear decommissioning trusts
Assets:
Short-term investments	53	52
Global equity securities	2,228	2,144
Fixed-income securities	2,277	2,077
TOTAL ASSETS	4,580	4,291
Customer credit trust
Assets:
Short-term investments	1	49
Global equity securities	186	71
Fixed-income securities	190	113
TOTAL ASSETS	377	233
Rabbi trusts
Assets:
Short-term investments	107	102
Global equity securities	6	5
Life insurance contracts	66	65
TOTAL ASSETS	179	172
Long-term disability trust
Assets:
Short-term investments	4	7
TOTAL ASSETS	134	146
Electricity
Assets:
Price risk management instruments, netting	(6)	(1)
Price risk management instruments, assets	403	410
Liabilities:
Price risk management instruments, netting	(6)	(6)
Price risk management instruments, liabilities	279	250
Gas
Assets:
Price risk management instruments, netting	(10)	43
Price risk management instruments, assets	0	46
Liabilities:
Price risk management instruments, netting	(10)	(48)
Price risk management instruments, liabilities	24	28
Level 1
Assets:
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	5,612	3,830
Liabilities:
TOTAL LIABILITIES	0	0
Level 1 | Short-term investments
Assets:
Short-term investments	826	203
Level 1 | PERS
Assets:
Short-term investments	905
TOTAL ASSETS	905
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	53	52
Global equity securities	2,228	2,144
Fixed-income securities	1,250	1,168
TOTAL ASSETS	3,531	3,364
Level 1 | Customer credit trust
Assets:
Short-term investments	1	49
Global equity securities	186	71
Fixed-income securities	46	29
TOTAL ASSETS	233	149
Level 1 | Rabbi trusts
Assets:
Short-term investments	107	102
Global equity securities	6	5
Life insurance contracts	0	0
TOTAL ASSETS	113	107
Level 1 | Long-term disability trust
Assets:
Short-term investments	4	7
TOTAL ASSETS	4	7
Level 1 | 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 | 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:
Price risk management instruments, gross subject to netting	36	10
TOTAL ASSETS	1,273	1,068
Liabilities:
TOTAL LIABILITIES	71	119
Level 2 | Short-term investments
Assets:
Short-term investments	0	0
Level 2 | PERS
Assets:
Short-term investments	0
TOTAL ASSETS	0
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	1,027	909
TOTAL ASSETS	1,027	909
Level 2 | Customer credit trust
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	144	84
TOTAL ASSETS	144	84
Level 2 | Rabbi trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Life insurance contracts	66	65
TOTAL ASSETS	66	65
Level 2 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 2 | Electricity
Assets:
Price risk management instruments, gross subject to netting	26	7
Liabilities:
Price risk management instruments, gross subject to netting	37	43
Level 2 | Gas
Assets:
Price risk management instruments, gross subject to netting	10	3
Liabilities:
Price risk management instruments, gross subject to netting	34	76
Level 3
Assets:
Price risk management instruments, gross subject to netting	383	404
TOTAL ASSETS	383	404
Liabilities:
TOTAL LIABILITIES	248	213
Level 3 | Short-term investments
Assets:
Short-term investments	0	0
Level 3 | PERS
Assets:
Short-term investments	0
TOTAL ASSETS	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	0
Global equity securities	0	0
Fixed-income securities	0	0
TOTAL ASSETS	0	0
Level 3 | Rabbi trusts
Assets:
Short-term investments	0	0
Global equity 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 | Electricity
Assets:
Price risk management instruments, gross subject to netting	383	404
Liabilities:
Price risk management instruments, gross subject to netting	248	213
Level 3 | Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Assets measured at NAV | Nuclear decommissioning trusts
Assets:
Assets measured at NAV	22	18
Assets measured at NAV | Long-term disability trust
Assets:
Assets measured at NAV	$ 130	$ 139

XML

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	Dec. 31, 2024 USD ($) $ / shares	Dec. 31, 2023 USD ($) $ / shares
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 403	$ 456
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	366	357
Liabilities | $	121	134
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	17	47
Liabilities | $	$ 127	$ 79
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)	(951)	(924)
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)	50,044	16,697
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)	2	1
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)	0	1
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)	126	190
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)	47	60

XML

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Asset balance, Beginning of period	$ 191	$ 199
Included in regulatory assets and liabilities or balancing accounts	(64)	(8)
Asset balance, End of period	$ 127	$ 191

XML

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Carrying Amount
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 5,358	$ 4,548
Carrying Amount | Convertible Notes Due 2027 | Secured Debt
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	2,100
Carrying Amount | Pacific Gas & Electric Co (Utility)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	37,812	35,909
Level 2 | Fair Value
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	5,829	4,695
Level 2 | Fair Value | Convertible Notes Due 2027 | Secured Debt
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	2,200
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	$ 34,532	$ 32,866

XML

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Securities, Available-for-sale [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$ 747	$ 717
Nuclear decommissioning trusts
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	2,748	2,536
Total Unrealized Gains	1,927	1,852
Total Unrealized Losses	(95)	(97)
Total Fair Value	4,580	4,291
Nuclear decommissioning trusts | Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	54	52
Total Unrealized Gains	0	0
Total Unrealized Losses	(1)	0
Total Fair Value	53	52
Nuclear decommissioning trusts | Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	353	381
Total Unrealized Gains	1,907	1,792
Total Unrealized Losses	(10)	(11)
Total Fair Value	2,250	2,162
Nuclear decommissioning trusts | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	2,341	2,103
Total Unrealized Gains	20	60
Total Unrealized Losses	(84)	(86)
Total Fair Value	2,277	2,077
Customer credit trust
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	355	216
Total Unrealized Gains	29	18
Total Unrealized Losses	(7)	(1)
Total Fair Value	377	233
Customer credit trust | Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1	49
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	1	49
Customer credit trust | Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	161	56
Total Unrealized Gains	28	16
Total Unrealized Losses	(3)	(1)
Total Fair Value	186	71
Customer credit trust | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	193	111
Total Unrealized Gains	1	2
Total Unrealized Losses	(4)	0
Total Fair Value	$ 190	$ 113

XML

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Nuclear decommissioning trusts
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 4,580	$ 4,291
Nuclear decommissioning trusts | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	35
1–5 years	742
5–10 years	517
More than 10 years	983
Total maturities of fixed-income securities	2,277	2,077
Customer credit trust
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	377	233
Customer credit trust | Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	0
1–5 years	44
5–10 years	36
More than 10 years	110
Total maturities of fixed-income securities	$ 190	$ 113

XML

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 1,980.0	$ 2,235.0	$ 3,316.0
Nuclear decommissioning trusts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,980.0	2,235.0	3,316.0
Gross realized gains on securities	255.0	80.0	2.0
Gross realized losses on securities	(63.0)	(74.0)	(3.0)
Customer credit trust
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from sales and maturities of nuclear decommissioning trust investments	398.0	556.0	250.0
Gross realized gains on securities	10.0	23.0	10.0
Gross realized losses on securities	(8.0)	(19.0)	$ (41.0)
Impairment write down	$ 0.0	$ 4.0

XML

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Funded Status:
Noncurrent liability	$ (808)	$ (476)
Pension Plan
Change in plan assets:
Fair value of plan assets at beginning of year	17,211	16,369
Actual return on plan assets	218	1,518
Company contributions	337	336
Benefits and expenses paid	(999)	(1,012)
Fair value of plan assets at end of year	16,767	17,211	$ 16,369
Change in benefit obligation:
Benefit obligation at beginning of year	17,697	16,608
Service cost for benefits earned	396	379	575
Interest cost	916	913	692
Actuarial loss/(gain)	(424)	809
Benefits and expenses paid	(1,000)	(1,012)
Benefit obligation at end of year	17,585	17,697	16,608
Funded Status:
Current liability	(10)	(9)
Noncurrent liability	(808)	(477)
Net (liability) asset at end of year	(818)	(486)
Accumulated benefit obligation	15,800	16,300
PBOP Plans
Change in plan assets:
Fair value of plan assets at beginning of year	2,499	2,336
Actual return on plan assets	74	260
Company contributions	5	5
Plan participant contribution	84	81
Benefits and expenses paid	(191)	(183)
Fair value of plan assets at end of year	2,471	2,499	2,336
Change in benefit obligation:
Benefit obligation at beginning of year	1,377	1,339
Service cost for benefits earned	41	38	62
Interest cost	71	73	53
Actuarial loss/(gain)	(123)	8
Benefits and expenses paid	(174)	(165)
Federal subsidy on benefits paid	3	3
Plan participant contributions	84	81
Benefit obligation at end of year	1,279	1,377	$ 1,339
Funded Status:
Noncurrent asset	1,192	1,122
Noncurrent liability	0	0
Net (liability) asset at end of year	1,192	1,122
PBOP Plans | Postretirement Life Insurance Plan
Change in plan assets:
Fair value of plan assets at beginning of year	292
Fair value of plan assets at end of year	296	292
Change in benefit obligation:
Benefit obligation at beginning of year	275
Benefit obligation at end of year	$ 261	$ 275

XML

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 396	$ 379	$ 575
Interest cost	916	913	692
Expected return on plan assets	(1,014)	(981)	(1,189)
Amortization of prior service cost	(3)	(4)	(4)
Amortization of net actuarial gain (loss)	1	1	2
Net periodic benefit cost	296	308	76
Less: transfer to regulatory account	39	25	254
Total expense recognized	335	333	330
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	41	38	62
Interest cost	71	73	53
Expected return on plan assets	(139)	(132)	(130)
Amortization of prior service cost	3	3	7
Amortization of net actuarial gain (loss)	(23)	(19)	(40)
Special termination benefits	0	0	22
Net periodic benefit cost	$ (47)	$ (37)	$ (26)

XML

EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.10%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.76%	5.21%	5.54%
Rate of future compensation increases	4.80%	3.80%	3.80%
Expected return on plan assets	6.40%	6.00%	6.10%
Interest crediting rate for cash balance plan	4.41%	3.86%	4.19%
PBOP Plans | Minimum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.71%	5.18%	5.50%
Expected return on plan assets	3.90%	3.70%	3.70%
PBOP Plans | Maximum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.76%	5.22%	5.54%
Expected return on plan assets	7.20%	7.00%	7.30%

XML

EMPLOYEE BENEFIT PLANS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) noncallable_bond	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Assumed health care cost trend rate	7.50%
Ultimate trend rate	4.50%
Assumed return	6.40%
10 year actual rate of return	5.10%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond	858
Total fair value of trust other net liabilities	$ 0	$ 10,000,000
Retirement savings plan expense	$ 175,000,000	$ 158,000,000	$ 144,000,000
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
10 year actual rate of return	6.40%	6.00%	6.10%
Company contributions	$ 337,000,000	$ 336,000,000
Expected employer contribution next year	327,000,000
Long-term Disability Trusts
Defined Benefit Plan Disclosure [Line Items]
Company contributions	31,000,000
Expected employer contribution next year	31,000,000
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Company contributions	$ 5,000,000	$ 5,000,000

XML

EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
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		26.00%	26.00%
Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		1.00%	1.00%
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		65.00%	65.00%
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		29.00%	28.00%
PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		0.00%	1.00%
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		3.00%	3.00%
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		68.00%	68.00%
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	30.00%
Forecast | PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	0.00%
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	67.00%

XML

EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	$ 19,238	$ 19,720
Level 3
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	16	13	$ 8
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	16,767	17,214
Assets measured at NAV	16,767	17,211	16,369
Pension Plan | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	173	651
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,310	1,270
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	437	472
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8,563	8,741
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	4,053	4,233
Pension Plan | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	126	565
Pension Plan | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,310	1,270
Pension Plan | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	437	472
Pension Plan | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,180	1,926
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	6,414	6,888
Pension Plan | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	47	86
Pension Plan | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
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	6,367	6,802
Pension Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	16	13
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 | 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	16	13
Pension Plan | Assets measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	6,284	6,080
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,471	2,506
Assets measured at NAV	2,471	2,499	$ 2,336
PBOP Plans | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	27	30
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	60	66
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	20	32
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,183	1,218
PBOP Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	538	550
PBOP Plans | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	27	30
PBOP Plans | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	60	66
PBOP Plans | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	20	32
PBOP Plans | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	431	422
PBOP Plans | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	751	795
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	751	795
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 | Assets measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	$ 1,181	$ 1,160

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EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets at beginning of year	$ 13	$ 8
Actual return on plan assets:
Relating to assets still held at the reporting date	9	2
Relating to assets sold during the period	(9)	(1)
Purchases, issuances, sales, and settlements:
Purchases	14	10
Settlements	(11)	(6)
Fair value of plan assets at end of year	$ 16	$ 13

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EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2025	$ 969
2026	1,055
2027	1,083
2028	1,109
2029	1,133
2030-2034	5,997
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
2025	81
2026	84
2027	87
2028	89
2029	91
2030-2034	473
Federal Subsidy
Defined Benefit Plan Disclosure [Line Items]
2025	(1)
2026	(1)
2027	(2)
2028	(2)
2029	(2)
2030-2034	$ (11)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Related Party Transaction [Line Items]
Utility reveneus	$ 24,419	$ 24,428	$ 21,680
Utility expenses	19,960	21,757	19,843
Pacific Gas & Electric Co (Utility)
Related Party Transaction [Line Items]
Utility reveneus	24,419	24,428	21,680
Utility expenses	19,939	21,746	19,759
Pacific Gas & Electric Co (Utility) | Administrative services provided to PG&E Corporation | Related Party
Related Party Transaction [Line Items]
Utility reveneus	3	3	3
Pacific Gas & Electric Co (Utility) | Administrative services received from PG&E Corporation | Related Party
Related Party Transaction [Line Items]
Utility expenses	66	80	104
Pacific Gas & Electric Co (Utility) | Utility employee benefit due to PG&E Corporation | Related Party
Related Party Transaction [Line Items]
Utility expenses	$ 81	$ 74	$ 85

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Accounts payable - other	$ 748	$ 851
Pacific Gas & Electric Co (Utility)
Related Party Transaction [Line Items]
Accounts payable - other	729	820
Pacific Gas & Electric Co (Utility) | Related Party
Related Party Transaction [Line Items]
Receivables	25	26
Accounts payable - other	$ 11	$ 24

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WILDFIRE-RELATED CONTINGENCIES - Litigation Payments (Details) $ in Millions	Dec. 31, 2024 USD ($)
Loss Contingencies [Line Items]
Litigation payment	$ 2,335
2019 Kincade Fire
Loss Contingencies [Line Items]
Litigation payment	958
2021 Dixie fire
Loss Contingencies [Line Items]
Litigation payment	1,359
2022 Mosquito fire
Loss Contingencies [Line Items]
Litigation payment	$ 18

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WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2020 Zogg Fire, 2021 Dixie Fire and 2022 Mosquito Fire) (Details) numberOfPeople in Millions, $ in Millions			3 Months Ended		12 Months Ended
	Jul. 13, 2021 USD ($) a structure injury	Nov. 04, 2019 numberOfPeople	Dec. 31, 2024 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2024 USD ($)	Feb. 05, 2025 numberOfClaimHolder notice plaintiff company complaint	Dec. 31, 2023 USD ($)	Sep. 06, 2022 a structure numberOfFatality injury	Oct. 23, 2019 a injury structure numberOfFatality
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
Loss contingency liability			$ 1,225		$ 1,225		$ 1,125
Potential loss contingency			25	$ 75	100
Insurance receivable fully collected							430
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
Loss contingency liability							1,600
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
Estimated losses			1,925		1,925
Loss contingency, costs incurred	$ 650
Insurance receivable			527		527
Probable of recovery					2,054
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
Number of residential structures destroyed (structure) | structure								44
Number of detached structures destroyed (structure) | structure								40
Insurance receivable			90		90
Probable of recovery					150
Percentage of fire contained								100.00%
Subsequent Event | 2019 Kincade Fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint						133
Number of plaintiffs represented by complaints | plaintiff						2,960
Subsequent Event | 2021 Dixie fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | numberOfClaimHolder						182
Number of plaintiffs represented by complaints | numberOfClaimHolder						8,681
Subsequent Event | 2022 Mosquito fire
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint						25
Number of plaintiffs represented by complaints | notice						2,738
Number of public entities who files complaints | company						6
Wildfire Fund | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery					925
Probable of recovery received					169
Wildfire Fund | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery					0
FERC TO rates | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery					94
FERC TO rates | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery					7
WEMA | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery					508
WEMA | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery					53
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
Pacific Gas & Electric Co (Utility) | 2021 Dixie fire
Loss Contingencies [Line Items]
Potential loss contingency			$ 50	$ 275	$ 325

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WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
2019 Kincade Fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	$ 458
Accrued Losses	100
Payments	(291)
Loss accrual, ending balance	267
2021 Dixie fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	870
Accrued Losses	325
Payments	(628)
Loss accrual, ending balance	567
2022 Mosquito fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	85
Accrued Losses	0
Payments	(3)
Loss accrual, ending balance	$ 82

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WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	$ 2,054
Probable of recovery, legal costs	123
2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	150
Probable of recovery, legal costs	50
Insurance | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	527
Insurance | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	90
FERC TO rates | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	94
FERC TO rates | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	7
WEMA | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	508
WEMA | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	53
Wildfire Fund | 2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	925
Wildfire Fund | 2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	$ 0

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WILDFIRE-RELATED CONTINGENCIES (Self-Insurance) (Details) - CPUC $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Loss Contingencies [Line Items]
Self insurance amount	$ 1,000
Self insurance deductible, percent	0.05
Self insurance deductible maximum	$ 50

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WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	$ 389
Accrued insurance recoveries	28
Reimbursements	(300)
Insurance Receivable, Ending Balance	117
2021 Dixie fire
Insurance Receivable [Roll Forward]
Insurance receivable	527
Insurance Receivable, Beginning Balance	326
Accrued insurance recoveries	1
Reimbursements	(300)
Insurance Receivable, Ending Balance	27
2022 Mosquito fire
Insurance Receivable [Roll Forward]
Insurance receivable	90
Insurance Receivable, Beginning Balance	63
Accrued insurance recoveries	27
Reimbursements	0
Insurance Receivable, Ending Balance	$ 90

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WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
2021 Dixie fire
Loss Contingencies [Line Items]
Probable of recovery	$ 2,054
2021 Dixie fire | FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	94
2021 Dixie fire | WEMA
Loss Contingencies [Line Items]
Probable of recovery	508
2022 Mosquito fire
Loss Contingencies [Line Items]
Probable of recovery	150
2022 Mosquito fire | FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	7
2022 Mosquito fire | WEMA
Loss Contingencies [Line Items]
Probable of recovery	$ 53

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WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions		12 Months Ended
	Aug. 23, 2019	Dec. 31, 2024	Dec. 31, 2023
Loss Contingencies [Line Items]
Disallowance cap, transmission and distribution 2022 equity rate base		$ 4,100
Initial safety certification, documentation provided, period	90 days
Initial safety certification, period	12 months
Expected capitalization, proceeds of bond		$ 21,000
Extension period		15 years
Expected capitalization, initial contribution		$ 7,500
Expected capitalization, annual contribution		$ 300
Annual contribution period		10 years
Loss contingency, estimate for life		20 years
Insurance receivable		$ 117	$ 389
2021 Dixie fire
Loss Contingencies [Line Items]
Insurance receivable		27	$ 326
2021 Dixie fire | Noncurrent assets – other
Loss Contingencies [Line Items]
Insurance receivable		600
2021 Dixie fire | Noncurrent assets – other | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Insurance receivable		$ 156

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WILDFIRE-RELATED CONTINGENCIES (Changes in Accrued Wildfire Fund Recoveries) (Details) - 2021 Dixie fire $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Loss Contingency Accrual [Roll Forward]
Wildfire Fund Receivable, Beginning Balance	$ 600
Accrued Wildfire Fund recoveries	325
Claims paid by Wildfire Fund	(169)
Wildfire Fund Receivable, Ending Balance	$ 756

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Securities Litigation and Claims in District Court) (Details) - Wildfire-Related Class Action $ in Millions	Dec. 31, 2024 USD ($)	Feb. 22, 2019 notice	Jun. 30, 2018 lawsuit
Loss Contingencies [Line Items]
Loss contingency liability | $	$ 300
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit			2
Number of public offerings of notes with complaints against underwriters (offering) | notice		4
Percentage of common stock owned, Fire Victim Trust if common issues additional shares	22.19%

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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) - Pacific Gas & Electric Co (Utility) $ in Millions	Aug. 22, 2024 USD ($)
TO18
Loss Contingencies [Line Items]
Settlement refund amount	$ 236
TO19
Loss Contingencies [Line Items]
Settlement refund amount	358
TO20
Loss Contingencies [Line Items]
Settlement refund amount	405
Transmission Revenue Requirement Reconciliation Memorandum Account
Loss Contingencies [Line Items]
Settlement refund amount	$ 473

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OTHER CONTINGENCIES AND COMMITMENTS (Interim Rate Relief Subject to Refund) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	Sep. 16, 2024	Mar. 07, 2024	Dec. 01, 2023	Jun. 15, 2023	Jun. 08, 2023	Dec. 15, 2022
2022 WMCE Interim Rate Relief
Loss Contingencies [Line Items]
Cost recovery						$ 1,360
Interim revenue requirement						1,290
Recorded expenditures, expenses						1,200
Recorded expenditures, capital expenditures						$ 136
Interim rate relief					$ 1,100
Remaining value recoverable					$ 224
Wildfire and Gas Safety Costs Interim Rate Relief
Loss Contingencies [Line Items]
Cost recovery				$ 2,500
Interim revenue requirement				688
Interim rate relief		$ 516
Remaining value recoverable		$ 172
Wildfire Costs Interim Rate Relief
Loss Contingencies [Line Items]
Recorded expenditures, expenses				726
Recorded expenditures, capital expenditures				1,500
Gas Safety Costs Interim Rate Relief
Loss Contingencies [Line Items]
Recorded expenditures, expenses				120
Recorded expenditures, capital expenditures				$ 118
2023 WMCE Interim Rate Relief
Loss Contingencies [Line Items]
Cost recovery			$ 2,180
Interim revenue requirement			1,860
Recorded expenditures, expenses			1,600
Recorded expenditures, capital expenditures			559
Interim rate relief	$ 944
Remaining value recoverable	$ 914
2023 WMCE Interim Rate Relief, CEMA Event
Loss Contingencies [Line Items]
Recorded expenditures, expenses			239
Recorded expenditures, capital expenditures			$ 167

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OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Accrued legal liabilities	$ 74	$ 89

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Topock natural gas compressor station	$ 294	$ 276
Hinkley natural gas compressor station	97	104
Former MGP sites owned by the Utility or third parties	782	809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	76	107
Fossil fuel-fired generation facilities and sites	18	19
Total environmental remediation liability	$ 1,267	$ 1,315

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OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 1,100
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 211
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	$ 123
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 637
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	$ 67
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	$ 16

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OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Purchase Commitments) (Details)	12 Months Ended
	Dec. 31, 2024 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	$ 500,000,000
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	16,300,000,000
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	500,000,000
Maximum annual payment incurred per event under the loss sharing program	332,000,000
Maximum annual payment incurred per event under the loss sharing program	$ 49,000,000
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
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation	$ 42,000,000

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OTHER CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long-term Purchase Commitment [Line Items]
2025	$ 3,717
2026	3,328
2027	3,170
2028	2,919
2029	2,682
Thereafter	17,005
Total purchase commitments	32,821
Renewable Energy
Long-term Purchase Commitment [Line Items]
2025	2,010
2026	1,952
2027	1,896
2028	1,875
2029	1,831
Thereafter	14,229
Total purchase commitments	23,793
Conventional Energy
Long-term Purchase Commitment [Line Items]
2025	910
2026	866
2027	800
2028	800
2029	716
Thereafter	2,730
Total purchase commitments	6,822
Natural Gas
Long-term Purchase Commitment [Line Items]
2025	443
2026	348
2027	190
2028	103
2029	92
Thereafter	41
Total purchase commitments	1,217
Other
Long-term Purchase Commitment [Line Items]
2025	354
2026	162
2027	284
2028	141
2029	43
Thereafter	5
Total purchase commitments	$ 989

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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, 2024	Dec. 31, 2023	Dec. 31, 2022
Power Purchases and Electric Capacity
Third-Party Power Purchase Agreements [Line Items]
Costs incurred for power purchases and electric capacity	$ 2,100	$ 2,400	$ 2,800
Nuclear Fuel
Third-Party Power Purchase Agreements [Line Items]
Payments for nuclear fuel	294	180	44
Gas Contracts
Third-Party Power Purchase Agreements [Line Items]
Cost of goods	$ 800	$ 2,500	$ 2,400

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2025	$ 84
2026	44
2027	47
2028	37
2029	34
Thereafter	333
Total minimum payments	$ 579

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OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2040	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2025	Jul. 11, 2024	Jul. 11, 2023
Operating Leased Assets [Line Items]
Payments for other commitments		$ 105	$ 106	$ 63
Oakland Headquarters Lease | Pacific Gas & Electric Co (Utility)
Operating Leased Assets [Line Items]
Purchase price							$ 906
Purchase price, deposits						$ 250	$ 150
Oakland Headquarters Lease | Pacific Gas & Electric Co (Utility) | Forecast
Operating Leased Assets [Line Items]
Purchase price, deposits					$ 506
SB 901 securitization | Secured Debt
Operating Leased Assets [Line Items]
Shareholder contribution amount		$ 650
SB 901 securitization | Secured Debt | Forecast
Operating Leased Assets [Line Items]
Shareholder contribution amount	$ 775
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 – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating expenses	$ (19,960)	$ (21,757)	$ (19,843)
Interest income	604	606	162
Interest expense	(3,051)	(2,850)	(1,917)
Other income, net	300	272	394
Income tax benefit	(200)	(1,557)	(1,338)
Net Income	2,512	2,256	1,814
Preferred Stock Dividends and Other Adjustments	37	14	14
Income Available for Common Shareholders	2,475	2,242	1,800
Income Available for Common Shareholders	2,475	2,242	1,800
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations, tax	3	6	8
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)	(16)	21
Net unrealized gain on available-for-sale securities	0	3	3
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $3, and $3, respectively)	1	8	(6)
Total other comprehensive income (loss)	$ (6)	$ (8)	$ 15
Weighted Average Common Shares Outstanding, Basic (in shares)	2,141	2,064	1,987
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,147	2,138	2,132
Net earnings (loss) per common share, basic (in dollars per share)	$ 1.16	$ 1.09	$ 0.91
Net earnings (loss) per common share, diluted (in dollars per share)	$ 1.15	$ 1.05	$ 0.84
PG&E Corporation
Operating expenses	$ (167)	$ (165)	$ (193)
Interest income	15	13	3
Interest expense	(270)	(365)	(261)
Other income, net	(17)	(21)	(201)
Equity in earnings of subsidiaries	2,697	2,530	2,154
Income Before Income Taxes	2,404	2,146	1,611
Income tax benefit	(94)	(96)	(132)
Net Income	2,498	2,242	1,743
Preferred Stock Dividends and Other Adjustments	23	0	0
Income Available for Common Shareholders	2,475	2,242	1,743
Income Available for Common Shareholders	2,475	2,242	1,743
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations, tax	3	6	8
Pension and other postretirement benefit plans obligations (net of taxes of $3, $6, and $8, at respective dates)	(7)	(16)	21
Net unrealized gain on available-for-sale securities	0
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $0, $3, and $3, respectively)	1	0	0
Total other comprehensive income (loss)	(6)	(16)	21
Comprehensive Income	$ 2,469	$ 2,226	$ 1,764
Weighted Average Common Shares Outstanding, Basic (in shares)	2,141	2,064	2,235
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,147	2,138	2,380
Net earnings (loss) per common share, basic (in dollars per share)	$ 1.16	$ 1.09	$ 0.78
Net earnings (loss) per common share, diluted (in dollars per share)	$ 1.15	$ 1.05	$ 0.73
PG&E Corporation | Administrative service revenue
Administrative service revenue	$ 146	$ 154	$ 109

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SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current Assets
Cash and cash equivalents	$ 940	$ 635	$ 734
Restricted cash and cash equivalents	273	297	213
Other	999	1,375
Total current assets	17,216	14,383
Other Noncurrent Assets
TOTAL ASSETS	133,660	125,698
Current Liabilities
Other current liabilities	3,658	4,698
Total current liabilities	16,330	17,314
Noncurrent Liabilities
Long-term debt	53,569	50,975
Other noncurrent liabilities	4,166	3,633
Total noncurrent liabilities	86,929	83,092
Shareholders’ Equity
Mandatory convertible preferred stock	1,579	0
Common stock	31,555	30,374
Reinvested earnings	(2,966)	(5,321)
Accumulated other comprehensive loss	(19)	(13)
Total shareholders’ equity	30,149	25,040
TOTAL LIABILITIES AND EQUITY	133,660	125,698
PG&E Corporation
Current Assets
Cash and cash equivalents	235	192	125
Restricted cash and cash equivalents	1	3	$ 0
Receivables	13	24
Income taxes receivable	2	2
Other	0	1
Total current assets	251	222
Other Noncurrent Assets
Investments in subsidiaries	42,829	36,804
Other investments	175	167
Deferred income taxes	633	539
Total other noncurrent assets	43,637	37,510
TOTAL ASSETS	43,888	37,732
Current Liabilities
Accounts payable – other	36	58
Income taxes payable	1	1
Other current liabilities	420	363
Total current liabilities	457	422
Noncurrent Liabilities
Long-term debt	5,612	4,599
Other noncurrent liabilities	141	141
Total noncurrent liabilities	5,753	4,740
Shareholders’ Equity
Common stock	39,086	37,906
Reinvested earnings	(2,966)	(5,322)
Accumulated other comprehensive loss	(21)	(14)
Total shareholders’ equity	37,678	32,570
TOTAL LIABILITIES AND EQUITY	$ 43,888	$ 37,732

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SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash Flows from Operating Activities
Net Income		$ 2,512	$ 2,256	$ 1,814
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and tax credits, net		1,098	(765)	(452)
Net cash provided by operating activities		8,035	4,747	3,721
Cash Flows from Investing Activities
Net cash used in investing activities		(11,375)	(9,162)	(10,214)
Cash Flows From Financing Activities:
Repayments under term loan credit facilities		(10,122)	(10,540)	(9,750)
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates		0	2,123	0
Premium, discount, and issuance costs on proceeds from long-term debt		5	67	29
Repayments of long-term debt		(800)	(3,075)	(5,968)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $5, $67, and $29 at respective dates		4,495	5,483	4,271
Common stock issued		1,128	0	0
Mandatory convertible preferred stock issued		1,579	0	0
Common stock dividends paid		(86)	0	0
Other		(59)	(17)	53
Net cash provided by financing activities		3,621	4,400	7,133
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents		281	(15)	640
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1		932	947	307
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31		1,213	932	947
Less: Restricted cash and restricted cash equivalents		(273)	(297)	(213)
Cash and cash equivalents		940	635	734
Supplemental disclosures of cash flow information Cash paid for:
Interest, net of amounts capitalized		(2,421)	(2,286)	(1,607)
Noncash Investing and Financing Items [Abstract]
Changes to PG&E Corporation common stock and treasury stock in connection with share exchanges with the Fire Victim Trust		0	(2,517)	(2,337)
Dividends declared but not yet paid		55	21	0
Convertible Notes Due 2027
Cash Flows From Financing Activities:
Premium, discount, and issuance costs on proceeds from long-term debt		0	27	0
Series A Preferred Stock
Noncash Investing and Financing Items [Abstract]
Dividends declared but not yet paid		23	0	0
PG&E Corporation
Cash Flows from Operating Activities
Net Income		2,498	2,242	1,743
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization		53	4	95
Equity in earnings of subsidiaries		(2,699)	(2,530)	(2,160)
Deferred income taxes and tax credits, net		(94)	(116)	(126)
Current income taxes payable		0	9	0
Other		9	40	339
Net cash provided by operating activities		(233)	(351)	(109)
Cash Flows from Investing Activities
Investment in subsidiaries		(5,360)	(1,290)	(994)
Dividends received from subsidiaries	[1]	2,025	1,775	1,275
Net cash used in investing activities		(3,335)	485	281
Cash Flows From Financing Activities:
Repayments under term loan credit facilities		(500)	(2,181)	0
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $27, and $0 at respective dates		0	2,123	0
Premium, discount, and issuance costs on proceeds from long-term debt		0	27	0
Repayments of long-term debt		0	0	(28)
Intercompany note to PG&E Corporation		0	0	(145)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $5, $67, and $29 at respective dates		1,496	0	0
Common stock issued		1,128	0	0
Mandatory convertible preferred stock issued		1,579	0	0
Common stock dividends paid		(86)	0	0
Other		(8)	(6)	0
Net cash provided by financing activities		3,609	(64)	(173)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents		41	70	(1)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1		195	125	126
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31		236	195	125
Less: Restricted cash and restricted cash equivalents		(1)	(3)	0
Cash and cash equivalents		235	192	125
Supplemental disclosures of cash flow information Cash paid for:
Interest, net of amounts capitalized		(215)	(309)	(233)
Noncash Investing and Financing Items [Abstract]
Changes to PG&E Corporation common stock and treasury stock in connection with share exchanges with the Fire Victim Trust		0	(2,517)	(2,337)
Dividends declared but not yet paid		55	21	0
PG&E Corporation | Convertible Notes Due 2027
Cash Flows From Financing Activities:
Premium, discount, and issuance costs on proceeds from long-term debt		4	0	0
PG&E Corporation | Series A Preferred Stock
Noncash Investing and Financing Items [Abstract]
Dividends declared but not yet paid		$ 23	$ 0	$ 0

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

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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 445	$ 166	$ 171
Charged to Costs and Expenses	312	624	146
Charged to Other Accounts	0	0	0
Deductions	339	345	151
Balance at End of Period	$ 418	$ 445	$ 166