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, 2025
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _________ to  ___________
Commission<br>File Number	Exact Name of Registrant<br><br>as Specified In Its Charter	State or Other Jurisdiction of<br>Incorporation or Organization	IRS Employer<br>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<br>the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.<br>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, 2025, the last business day of the most recently completed second fiscal quarter:
---	---
PG&E Corporation common stock	$37,246 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation		Common Stock outstanding as of February 4, 2026:
---	---
PG&E Corporation:	2,675,711,544*
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 2026 Annual Meetings of Shareholders	Part III (Items 10, 11, 12, 13 and 14)

Contents

UNITS OF MEASUREMENT
GLOSSARY
FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. BUSINESS
Triple Bottom Line
Regulatory Environment
Environmental Regulation
Ratemaking Mechanisms
Human Capital
Electric Utility Operations
Natural Gas Utility Operations
Competition
Sustainability and Resiliency
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1C. CYBERSECURITY
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
RESULTS OF OPERATIONS
LIQUIDITY AND FINANCIAL RESOURCES
REGULATORY MATTERS
LEGISLATIVE AND REGULATORY INITIATIVES
LITIGATION AND OTHER MATTERS
ENVIRONMENTAL MATTERS
RISK MANAGEMENT ACTIVITIES
CRITICAL ACCOUNTINGESTIMATES
NEW ACCOUNTING PRONOUNCEMENTS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E Corporation
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF EQUITY
Pacific Gas and Electric Company
CONSOLIDATED STATEMENTS OF INCOME
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
NOTE 4: DEBT
NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION
NOTE 7: PREFERRED STOCK
NOTE 8: EARNINGS PER SHARE
NOTE 9: INCOME TAXES
NOTE 10: DERIVATIVES
NOTE 11: FAIR VALUE MEASUREMENTS
NOTE 12: EMPLOYEE BENEFIT PLANS
NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS
NOTE 14: WILDFIRE-RELATED CONTINGENCIES
NOTE 15: OTHER CONTINGENCIES AND COMMITMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No.34)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 16. FORM 10-K SUMMARY
SIGNATURES
SCHEDULE I - CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

UNITS OF MEASUREMENT

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 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet

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
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
Cal OES	California Governor’s Office of Emergency Services
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
Continuation Account	the account established statewide by SB 254 that expands the existing Wildfire Fund
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
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
FASB	Financial Accounting Standards Board
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
LSEs	load serving entities
LTIP	Long-Term Incentive Plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
MGMA	Microgrids Memorandum Account
MGP	manufactured gas plants
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceeding
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
Oakland General Office	300 Lakeside Drive, Oakland, California, 94612
OEIS	Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
PD	proposed decision
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
SCE	Edison International and Southern California Edison Company
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
SOFR	Secured Overnight Financing Rate
SPV	PG&E AR Facility, LLC
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)
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VMBA	Vegetation Management Balancing Account
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

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 liabilities; ratemaking and regulatory proceedings; capital expenditures; cost savings; load growth; customer rates; 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, and dividends. 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,” “on track,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

•the timing and outcomes of the 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;

•the extent to which the Wildfire Fund, the Continuation Account, and the 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 or the Continuation Account has sufficient remaining funds (which will be reduced as claims are made by California’s other participating electric utility companies);

•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; and the risk that the Utility is not able to recover costs from the Wildfire Fund, the Continuation Account, or other third parties or through rates;

•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 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, including 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 and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, increasing demand for electric power due to data centers and electrification of the transportation, buildings, and other sectors of the economy, and the resulting changes in customer demand for its natural gas and electric services;

•cyber or physical attacks, 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 remediation, compliance and other costs, lost revenues, litigation, investigations, or reputational harm;

•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 and the extent to which such costs are borne by PG&E Corporation, including those regarding:

◦wildfires, including inverse condemnation reform, wildfire self-insurance, the Wildfire Fund, the Continuation Account, 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 amounts of fines, penalties, remediation or other obligations resulting from 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;

•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 (including with respect to raw materials), import tariffs, and trade wars; 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;

•the risks and uncertainties associated with the resolution of the matters described in Note 14 of the Notes to the Consolidated Financial Statements under the headings “Wildfire-Related Securities Litigation” and “Indemnification Obligations”;

•the risks and uncertainties associated with PG&E Corporation’s and the Utility’s other ongoing or future litigation, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•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 procurement costs through rates;

•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, volatility in such capital markets, and changes in interest rates;

•the risks and uncertainties associated with high rates for the Utility’s customers, including reduced customer demand and approved amounts in the Utility’s ratemaking or cost recovery proceedings;

•actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings; 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: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K. 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.

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 PG&E Corporation’s website, www.pgecorp.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. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on PG&E Corporation’s website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the addresses of 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.

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 for the most recently completed year 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. PG&E Corporation and the Utility are separate entities.

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 this 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.

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, and equitably-paid workforce. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas 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. 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 adapting to 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’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 increased vehicle and building 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:

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

•Implemented contracts for more than 4.9 GW of battery energy storage capacity, strengthening California’s grid efficiency and reliability.

•Helped enable the total number of electric vehicles operating in the Utility’s service area to exceed 820,000.

•Brought the total number of interconnected private solar customers to more than 950,000.

•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.

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. All three credit ratings agencies have increased PG&E Corporation’s and the Utility’s issuer credit ratings since 2020.

PG&E Corporation's dividend policy entails consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings (a non-GAAP financial measure) by 2028. For more information, see Note 6 of the Notes to the Consolidated Financial Statements.

Total capital expenditures recorded in 2025 were $13.4 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be $12.4 billion for 2026, $13.4 billion for 2027, $15.4 billion for 2028, $16.3 billion for 2029, and $16.0 billion for 2030. The Utility has identified opportunities for investment in the coming years in addition to its forecast, including investments in transmission for data centers and system investments, transportation electrification capacity, hydroelectric facilities, energy storage, information technology, and automation. The Utility plans to submit a 10-year Electric Undergrounding Plan to the OEIS for review. The Utility will then submit an application requesting conditional approval of the plan’s costs to the CPUC. 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. Additionally, $2.85 billion of fire risk mitigation capital expenditures will be excluded from the Utility’s equity rate base pursuant to SB 254.

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.

PG&E Corporation and the Utility are committed to building a safe, reliable, sustainable, and climate-resilient energy system at an affordable 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 that reduces other customers’ bills. The Utility plans to meet its cost savings goal through increased efficiencies including waste elimination through the Lean operating system. The Utility expects data centers, electric vehicle adoption, and building electrification to drive load growth. For more information see “Competition” below. 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. The Utility has set a goal to limit average annual customer rate increases to 3%.

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.

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 the companies. 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. Waste elimination, the fifth Lean play, involves identifying and eliminating inefficiencies in both process and workflow in a sustainable manner and driving the continued adoption of consistent processes and improvements to financial visibility and controls.

The Utility has responded to wildfire risk by implementing operational changes and investing in safety, 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. The Utility has enabled EPSS in all high fire risk areas.

•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 sectionalizers, which enable more targeted de-energizations, and more granular risk models.

•Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and mitigate vegetation that might grow or fall into utility equipment. Additional inspections are conducted within a subset of HFTD areas. The Utility continues to leverage remote sensing technology to enhance data driven inspection planning and safe work execution.

•Asset inspections: Asset inspections identify equipment conditions before failure. The Utility’s asset inspection programs continue to grow more risk-informed, thorough, standardized, digitized, and verifiable.

•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 conductors with covered conductors and installing stronger poles, removing lines, serving customers through remote grids, or converting lines from overhead to underground.

In recent years, the Utility has introduced or expanded its use of several measures including clearing defensible space around transmission structures, downed conductor detection, partial voltage force outs, and transmission operational controls which further decreased wildfire ignition risk.

The Utility’s equipment was not involved in the ignition of any major wildfires in 2025. The Utility experienced a decreased number of CPUC-reportable ignitions in 2025, compared to 2024, due to continued operational improvements.

The Utility is also continuing to invest in a safe and reliable gas system. The Utility’s asset safety efforts include pipeline replacements, strength testing, and real-time monitoring systems. Additionally, the Utility educates the public and its workforce regarding safe digging practices and maintains rapid outage response protocols to protect public safety and minimize service disruptions.

The Utility’s generation operations focus on safety, compliance, environmental stewardship, and asset reliability. The Utility focuses on continuous improvement, risk informed decision-making, and 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.

Regulatory Environment

The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. The Utility is regulated primarily at the state level by the CPUC and at the federal level 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 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. 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.

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.

The OEIS is a state agency responsible for reviewing and approving or rejecting 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.

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 state and federal agencies responsible for implementing environmental laws.

The Utility maintains a comprehensive compliance program but may be liable for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former 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 have a reasonable opportunity 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”). 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 operating and maintaining the utility system are generally approved in the GRC, and 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;

•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 (i.e. the value of the Utility’s investments in generation and distribution assets and general plant).

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 net income is not impacted by fluctuations in sales. 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, Utility-owned electric generation operations, gas transmission and storage facilities, and an opportunity to earn authorized rate of return from the cost of capital decision. The CPUC conducts a GRC for the Utility every four years. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). Attrition year rate adjustments are generally 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 - 2027 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.

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 Case for 2024” 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. 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. 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

In lieu of the traditional rate-based return on investment, the Utility receives a fixed payment of $100 million plus a volumetric payment of $13 per MWh generated by DCPP. The fixed payment may be adjusted downward in the event of extended unplanned outages. The amounts of the fixed and volumetric payments are escalated annually by the CPUC. The volumetric payment cannot be realized as shareholder profits or paid out as dividends.

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. In addition, the utilities are required to obtain CPUC approval of their bundled procurement plans (“BPPs”), which are based on customer demand forecasts.

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 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. 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 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. The Utility may defer procurement of local resources to the CAISO’s backstop mechanisms if bid costs are deemed unreasonably high. In addition, the CPUC can order the Utility to seek to procure specific local capacity products, which are included as energy procurement costs. The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account, subject to demonstrating compliance to the CPUC.

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 generally recovers the cost of gas purchased on behalf of small commercial and residential customers, as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates. If the Utility’s costs average less than 99% of a market-based benchmark, then the Utility returns 80% of such savings to customers, subject to a cap; if the Utility’s costs average more than 102% of the benchmark, the Utility recovers 50% of such excess costs. As a result, changes in the price of natural gas 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, and if the nuclear decommissioning trusts are underfunded, 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, 2025, PG&E Corporation had 10 employees, and the Utility had approximately 29,000 regular employees. Of the Utility’s regular employees, approximately 17,500 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”) International Federation of Professional and Technical Engineers 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 expired on December 31, 2025, and have been automatically extended for at least one year while the parties negotiate successor agreements. The automatic extension does not cover general wage increases, which must be separately bargained and agreed to for 2026 and beyond. Under prior agreements, wages increased annually by 3.75% from 2022 through 2025. The IBEW, ESC, and SEIU represent approximately 60% 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 2025.

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 2025 was 3.8%. Approximately 46% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 19% of PG&E Corporation’s and the Utility’s employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

The Utility’s contractors and subcontractors include approximately 39,000 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 and equitably-paid 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, inclusion and belonging, environmental leadership, innovation, and community service. The Utility conducts employee surveys to measure and improve employee engagement.

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.

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 and qualified candidates that reflect the communities the Utility serves for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations. 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.

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 2025 STIP was focused on company objectives of safety, customer impact, and financial health.

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

Safety

The Utility’s strategy to deliver safety outcomes remains focused on employees, contractors, and public safety through identification, elimination, and mitigation of high-energy hazards. The Utility’s safety metrics include the number of actual serious injuries or fatalities (“SIF-A”) and high-energy events that had the potential to result in a serious injury or fatality per 200,000 hours worked (“SIF-P rate”). In 2025, the Utility had four SIF-A incidents, which resulted in one fatality and three serious injuries, and a SIF-P rate of 0.051. The Utility continues to mature its PG&E Safety Excellence Management System, which is a systematic approach to assess risk and evaluate or implement controls for safe operation based on industry standards.

Inclusion and Belonging

PG&E Corporation’s and the Utility’s goal is to foster a workplace culture of inclusion and belonging 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’ inclusion and belonging strategy, practices, and performance.

Key elements of PG&E Corporation’s and the Utility’s approach to 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 engagement programming and recognize employees’ contributions to organizational culture among the Utility’s workforce, communities, and customers. The Employee Resource Groups are open to all employees. Specialized teams facilitate awareness, education, and dialogue and support enterprise inclusion and belonging efforts.

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.

In 2025, the Utility estimated total net deliveries of electricity to retail customers were 24,052 GWh. This amount represents the total amount of electricity generated and procured, net of electricity sold into the CAISO open market or to third parties. Utility-owned resources generated approximately 60% of its net delivered electricity.

Of the 2025 estimated total net deliveries of electricity to retail customers from generated and procured resources, approximately 71% was generated from GHG-free resources (34% qualifying renewable energy resources, 32% nuclear, and 5% large hydroelectric), and 29% was generated from natural gas generation resources. Consistent with the RPS requirement, the Utility considers qualifying renewable energy resources to include bioenergy such as biogas and biomass, hydroelectric facilities that are 30 MW or less, wind, solar, and geothermal energy. The Utility’s percentage of GHG-free generation decreased in 2025, compared to 2024, because DCPP’s generation became attributable to all customers statewide (rather than only the Utility’s customers). This change does not represent a decrease in the Utility’s ownership of the DCPP resource; rather, the generation associated with this resource became attributed among other LSEs’ portfolios. For more information about California’s clean energy goals, see further below and in the “Sustainability and Resiliency” section below.

The Utility calculates net deliveries of electricity according to the Power Content Label methodology based on CEC guidelines.

Owned Generation Facilities

As of December 31, 2025, 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) DCPP consists of two nuclear power reactor units, Units 1 and 2. The NRC operating license for Unit 1 expired in 2024, and the operating license for Unit 2 expired 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.

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.

Energy Storage

Energy storage improves system reliability, supports California’s decarbonization goals by integrating increased levels of renewable energy, and assists in the event of customer demand growth. 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 2025.

As of December 31, 2025, the Utility owned 183 MW and has contracted for another 3,024 MW of operational energy storage capacity. The Utility has also procured 1,884 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 solicited and executed an agreement for long-duration storage, which is storage with at least eight hours of discharge capacity, in order to have this resource online by 2031. In September 2025 the CPUC also conditionally authorized the Utility to recover the costs, up to a cap, associated with increasing the nameplate generating capacity of its Helms Pumped Storage Facility.

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, 2025, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines. The Utility also operated 33 electric transmission substations. 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 109,000 circuit miles of distribution lines (of which, as of December 31, 2025, approximately 27% are underground and approximately 73% are overhead), 59 transmission and distribution substations, and 601 distribution substations. 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.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2023 through 2025 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 2025, 2024, or 2023.

	2025		2024		2023
Customers (average for the year)	5,656,450		5,606,873		5,584,185
Deliveries (in GWh) (1)	71,791		74,111		72,933
Revenues (in millions):
Residential	$	6,976	$	7,504	$	6,041
Commercial	7,022		7,201		5,643
Industrial	1,929		2,065		1,784
Agricultural	1,825		1,815		1,413
Public street and highway lighting	105		103		83
Other, net (2)	72		(47)		136
Subtotal	17,929		18,641		15,100
Regulatory balancing accounts (3)	389		(830)		2,324
Total operating revenues	$	18,318	$	17,811	$	17,424
Selected Statistics:
Average annual residential usage (kWh)	4,931		5,261		5,217
Average billed revenues per kWh:
Residential	$	0.2836	$	0.2888	$	0.2356
Commercial	0.2527		0.2528		0.2007
Industrial	0.1403		0.1475		0.1294
Agricultural	0.3636		0.3597		0.2984
Net plant investment per customer	$	12,710	$	11,460	$	10,720

(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.

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 2025, the Utility purchased approximately 304,000 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 56% of the total natural gas volume the Utility purchased during 2025.

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, 2025, the Utility’s natural gas system consisted of approximately 45,400 miles of distribution pipelines, approximately 5,500 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates seven 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.  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 2025, the Utility continued upgrading transmission pipelines to allow for the use of in-line inspection tools.

Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2023 through 2025 (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 2025, 2024 or 2023.

	2025		2024		2023
Customers (average for the year) (1)	4,633,685		4,614,080		4,605,628
Gas purchased (MMcf)	223,619		219,758		239,756
Average price of natural gas purchased (price per Mcf)	$	2.55	$	1.99	$	6.91
Bundled gas sales (MMcf):
Residential	147,827		146,842		171,889
Commercial	56,986		55,174		60,248
Total Bundled Gas Sales	$	204,813	$	202,016	$	232,137
Revenues (in millions):
Bundled gas sales:
Residential	$	3,651	$	3,089	$	3,686
Commercial	1,074		984		1,052
Other	101		159		(145)
Bundled gas revenues	4,826		4,232		4,593
Transportation service only revenue	1,937		1,815		1,603
Subtotal	6,763		6,047		6,196
Regulatory balancing accounts (2)	(146)		561		808
Total operating revenues	$	6,617	$	6,608	$	7,004
Selected Statistics:
Average annual residential usage (Mcf)	37		37		37
Average billed bundled gas sales revenues per Mcf:
Residential	$	24.39	$	20.74	$	20.73
Commercial	17.59		16.28		14.99
Net plant investment per customer	$	5,278	$	5,019	$	4,749

(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, 2025, DCPP achieved an average capacity factor of 90%. 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.

Competition

Trends in Market Demand

The Utility expects customer electric load to increase in coming years primarily as a result of data center usage, electric vehicle adoption, and building electrification. The Utility’s ability to accurately predict the location and pace of electric load growth is limited, due to factors such as extent of customer demand, the policy environment, and macroeconomics.

Load growth can reduce other customers' rates when the incremental revenue for the new load is greater than the incremental cost to serve that load. The degree to which load growth reduces other customers’ rates will depend on the pricing for the new load, which in turn depends on the unit cost of power for the new load, the costs to construct infrastructure to connect new load, the Utility’s cost to serve the new load, and the amount of power used. The Utility is engaged with regulators and other stakeholders on policies, such as cost allocation and rate design frameworks, that support conditions for load growth to improve affordability for customers.

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 Net Billing Tariff (“NBT”), reduces 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.

The Utility expects customer demand for gas to decrease in the coming years, primarily in response to policies supporting California’s climate goals.

Competitive Conditions in the Electricity Industry

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 CCAs 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 collects 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.

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 applicable 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.

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.

Competitive Conditions 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.

•60% of retail electricity sales to customers from renewable energy sources by 2030.

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

•Renewable and zero-carbon resources supplying 90% of utilities’ retail electricity 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 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 under a program known as the cap-and-trade program. In 2025, the changes to state law authorized the program through 2045. Entities with a compliance obligation, including entities that supply electricity and natural gas to California consumers, 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.

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

The current federal administration 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.

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 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 currently developing the next CAVA, which is expected to be more granular than the previous climate vulnerability assessment and will be submitted to the CPUC in 2027.

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 scientific information into its operations by reviewing relevant scientific literature. The Utility also works to incorporate customer and community perspectives in the CAVA process based on its engagement with CPUC-designated disadvantaged and vulnerable communities.

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. Their 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 following table shows the Utility’s third-party verified voluntary GHG inventory for 2024, which is the most recent data available. Measuring emissions data involves complex estimates and assumptions, which may change as a result of methodology changes.

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)	3,391,499
Scope 3 emissions (2)	36,445,372

(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.

(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 achieved a third-party verified CO2 emissions rate of 16 pounds of CO2 per MWh for electricity delivered to retail customers in 2024, using the CEC’s Power Source Disclosure program methodology.

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 2025 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.

Risks Related to Wildfires

The Wildfire Fund, Continuation Account, and other provisions of AB 1054 and SB 254 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 disallowance cap under AB 1054 and SB 254. Under AB 1054 and SB 254, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Continuation Account reimbursement and all aspects of the reformed prudent manager standard. The 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.

Furthermore, for the Continuation Account to be available for payment of eligible claims, the Wildfire Fund administrator must determine that the Continuation Account is necessary, the CPUC must authorize extending the non-bypassable charge, and there must be sufficient funds remaining in the Continuation Account. Funds in the Continuation Account may be depleted more quickly than PG&E Corporation and the Utility anticipate as a result of claims made by California’s other participating electric utility companies. PG&E Corporation and the Utility are also unable to predict whether the administrator will determine that additional contributions are needed, and if so, the timing of those contingent contributions.

If the Utility is unable to maintain a safety certification or if the Continuation Account is exhausted as a result of claims made by California’s other participating electric utility companies or otherwise, the unavailability or insufficiency of the Continuation Account 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 Continuation Account for wildfire-related losses in any year that such losses 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 accelerated amortization of the Wildfire Fund asset 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 and the Continuation Account has had, and is expected to continue 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 and the Continuation Account may not ultimately outweigh the substantial costs of the Utility’s contributions to the Wildfire Fund or the Continuation Account. See “Key Factors Affecting Financial Results” and “Critical Accounting Estimates” in Item 7. MD&A.

PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or the Wildfire-Related Securities Claims could exceed their estimated liabilities, 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 liability estimates for probable losses in connection with these fires do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. Similarly, PG&E Corporation’s and the Utility’s costs to resolve the Wildfire-Related Securities Claims could exceed their estimated liabilities. PG&E Corporation and 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. A hearing on the status of restitution in the Butte County District Attorney’s Office’s investigation into the 2018 Camp fire has been continued several times, most recently to April 24, 2026. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in the 2024 Form 10-K.

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 (“SDGE”) 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.

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 are 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, the 2022 Mosquito fire, and the Wildfire-Related Securities Claims, 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 $1.325 billion and $2.15 billion exceed the amounts of available liability insurance coverage of $430 million and $521 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, 2025, the Utility has recorded probable recoveries of $632 million and $61 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, Continuation Account, and other provisions of AB 1054 and SB 254 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 sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the 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.

Risks Related to Regulatory Proceedings, Investigations, and Enforcement Matters

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, and ultimately may not authorize, 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.

An Enhanced Oversight and Enforcement Process proceeding could result in the Utility losing its license to operate as a utility.

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 an EOEP proceeding, 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, which could be revoked). The process contains provisions for the Utility to cure and exit the process if it can satisfy specific criteria. The EOEP states that the Utility should presumptively move through the steps of the process sequentially, but the CPUC may place the Utility into the appropriate step of the process upon occurrence of a specified triggering event.

PG&E Corporation and the Utility could be adversely affected by legislative and regulatory developments, including through increased compliance costs and penalties.

PG&E Corporation, the Utility, and their 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 increase 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 and financial risk, significant litigation, and reputational harm.

PG&E Corporation and the Utility may also be affected by changes in laws or regulations, or their application, which could impact their business model, rates, rate base, cost recoveries, revenues, or spending, which in turn could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

For example, 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 for tax years beginning on or after 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 2028, the amount of which may become substantial in future years.

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

The Utility is subject to extensive federal, state, and local laws, regulations, and orders, including those regarding customer billing; customer service; affiliate transactions; wildfire mitigation initiatives and WMP targets (including EPSS, PSPS, vegetation management, asset inspections, and system hardening); design, construction, operating and maintenance practices; safety and inspection practices; federal electric reliability standards; environmental compliance; resource adequacy; GHG emissions; renewable energy; privacy, including laws like the California Consumer Privacy Act, as amended (“CCPA”), which permits consumers to exercise certain rights with respect to their personal information, including opting out of receiving certain communications and data sharing with third parties; and compliance with CPUC general orders (“GOs”) or other applicable CPUC decisions or regulations.

PG&E Corporation and the Utility collect and retain certain personal information of their customers, shareholders, and employees in connection with operating their business and have certain obligations to protect this data. For example, the CCPA requires a business to implement reasonable security procedures to safeguard personal information against unauthorized access, use, or disclosure. The personal information that PG&E Corporation and the Utility collect, as well as other commercially-sensitive data that they possess, could nonetheless become compromised or improperly disclosed, including through the use of generative artificial intelligence or as a result of a cyber incident, 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.

The Utility has been and could in the future be subject to regulatory or governmental enforcement actions with respect to its compliance with such rules.

The Utility is a target of a number of investigations, in addition to certain investigations in connection with wildfires, which could result in enforcement actions. See “Risks Related to Wildfires” above. PG&E Corporation and the Utility could be subject to additional investigations. The Utility is unable to predict the outcome of these pending or potential investigations, including whether they will result in enforcement actions, whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.

These investigations or enforcement actions could result in a judgment against the Utility. Failure to comply with laws and regulations could result in material fines, penalties, customer refunds, other payments, increased oversight, and changes in the Utility’s operations and business model, reputational harm, and other negative consequences. If the OEIS determines that the Utility has failed to substantially comply with its WMP, the CPUC will assess penalties. These consequences could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 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.

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.

Local jurisdictions attempt to acquire some of 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 an 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 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 causes assets to fail and results in 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 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 resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences;

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

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

•the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities; 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, physical attack, or technology failure” 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 of 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 have reduced, and will continue to 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.

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, physical attack, or technology failure.

The Utility relies on technology to operate its business, including complex operational, interconnected networks and information technology systems that support critical functions. The Utility also depends on information technology systems to help it monitor and operate the electric grid, detect ignitions and collect other wildfire-related information, process transactions, track and collect revenues, manage customer billing and energy usage data, maintain internal control over financial reporting, and produce accurate and timely financial statements and regulatory filings. These information technology systems allow the Utility to create, collect, use, disclose, store, and otherwise process sensitive information, including regarding customers, employees, and other individuals. These systems can be damaged or disrupted by malicious events such as cyber or physical attacks, or by technology failure.

Cyber attacks targeting utility systems are significant and are continuing to increase in sophistication, magnitude, and frequency. PG&E Corporation and the Utility face various cybersecurity threats, including attempts to gain unauthorized access to their systems and networks, including access to confidential information about the Utility, its customers and employees, denial-of-service attacks, threats to their information technology infrastructure, ransomware, and phishing attacks. 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 systems and networks, which could disrupt the Utility’s operations. Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats. Accordingly, 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.

The systems and networks of PG&E Corporation and the Utility may also be damaged or disrupted by technology failures due to errors in software or platforms or the inability to appropriately support, update, expand, recover or integrate technology within PG&E Corporation and the Utility’s networks.

PG&E Corporation and the Utility add, modify and replace information technology systems and technology vendors from time to time. The Utility is engaged in complex projects regarding its billing and enterprise resource planning systems. Modifying existing systems or implementing new or replacement systems or providers is costly and involves risks, including the risks involved in integrating with the Utility’s existing systems and processes, implementing associated changes in accounting procedures and controls, and ensuring that data conversion is accurate and consistent.

Physical attacks targeting the Utility’s physical assets or personnel have caused damage, disrupted operations, and caused injuries and could do so in the future.

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, damage the Utility’s assets or operations or those of third parties, increase costs, and impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting. 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.

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.

Operations at the Utility’s two nuclear generation units at DCPP could cease before their planned retirement dates in 2029 and 2030 as a result of new legislation, regulations, orders, or their interpretation, or as a result of operational costs. 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 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 as a result of labor union activity or pandemics. 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.

PG&E Corporation’s and the Utility’s business activities are concentrated in one industry and in one region.

PG&E Corporation’s and the Utility’s business activities are concentrated in one industry (electric and gas utility) and in one region (Northern and Central California). As a result, their business performance may be affected by events, environmental conditions and economic factors unique to such industry or region, or by regional regulation, legislation or judicial decisions, without the benefit of geographic or business diversification.

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 vegetation growth 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 and faces heightened fire risk. Local land use policies and forestry management practices also contribute to these risks by limiting precautionary or remedial activities.

Severe weather events, particularly wildfires, have had a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows, including through significant claims being made against the Utility. In addition, 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.

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 imposed by California. 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.

The Utility’s environmental remediation costs could exceed its liability estimates.

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.

Environmental remediation costs could also increase in the future as a result of new legislation or regulation. See “PG&E Corporation and the Utility could be adversely affected by legislative and regulatory developments, including through increased compliance costs and penalties” above.

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. For more information, 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 PG&E Corporation’s and the Utility’s Environment and Financial Condition

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, improve its work management, identify additional opportunities to convert expenses to capital expenditures, and improve organizational design. Even if the Utility is able to reduce some costs through such efforts, 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, which would offset the beneficial effect of such savings on net income. Moreover, under cost-of-service ratemaking, the Utility’s earnings depend in large part on its ability to manage costs, and if it is unable to manage costs effectively for the foregoing or any other reasons, PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows may be adversely affected.

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 or fails to reduce other customers’ bills to the extent 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” above.

In addition, 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 on customers, 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. Concerns about affordability could also result in new legislation, see “PG&E Corporation and the Utility could be adversely affected by legislative and regulatory developments, including through increased compliance costs and penalties” above. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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, 2025, PG&E Corporation had approximately $5.7 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 $55.3 billion of outstanding indebtedness. In addition, PG&E Corporation had $650 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $3.2 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. 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 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 such as wildfires; and

•limiting their ability to capitalize on business opportunities.

Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks. As a result of the high level of indebtedness, PG&E Corporation and the Utility may be unable to generate sufficient cash through operations to service such debt and may need to refinance such indebtedness at or prior to maturity and be unable to obtain financing on suitable terms or at all. As a capital-intensive company, the Utility relies on access to the capital markets, particularly investment grade capital markets. PG&E Corporation's and the Utility's substantial indebtedness may limit their ability to procure additional financing in the future and elevated interest rates, as experienced from 2022 to 2024, may further increase their interest expense. If the Utility were unable to access the capital markets or the cost of financing were to further 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. In addition, adverse changes in PG&E Corporation’s or the Utility’s credit ratings may increase their cost of capital or restrict their access to the financial markets.

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 their 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.

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 the Amended Articles, 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.

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, 2025, 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 $38.3 billion and $34.1 billion, respectively. PG&E Corporation 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 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 limitations. In general, an ownership change occurs if the aggregate value of the stock ownership of certain shareholders (generally five percent (5%) 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 financial obligations.

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, variable rate debt, and other inputs have increased and may continue to increase more quickly than expected as a result of inflation, import tariffs, fiscal and monetary policy, or other factors. 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 inflationary pressures and 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.

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, or are reasonably likely to materially affect, 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, physical attack, or technology failure” in Item 1A. Risk Factors.

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. Virtually all of the Utility’s plant property is subject to the lien of a first mortgage bond indenture.

In June 2025, the Utility closed on its acquisition of the Oakland General Office property, which serves as the headquarters of PG&E Corporation and the Utility. For more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

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 and Other 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.

SEC rules require disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the company reasonably believes will exceed a specified threshold. Consistent with SEC rules, each of PG&E Corporation and the Utility has elected to use $1 million as the quantitative threshold for disclosure of such proceedings.

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 and the Utility (as applicable), as of February 11, 2026.

Name	Age	Entity At Which Officer is an Executive Officer	Title	Time in Position
Patricia K. Poppe	57	PG&E Corporation	Chief Executive Officer, PG&E Corporation	January 2021 to present
			President and Chief Executive Officer, CMS Energy Corporation	July 2016 to December 2020
Carolyn J. Burke	58	PG&E Corporation	Executive Vice President and Chief Financial Officer, PG&E Corporation	May 2023 to present
			Chief Financial Officer & Executive Vice President, Chevron Phillips Chemical Company LLC	February 2019 to September 2022
Jason M. Glickman	45	PG&E Corporation, Utility	Executive Vice President, Strategy and<br>Growth, PG&E Corporation and Utility	January 2026 to present
			Executive Vice President, Engineering, Planning, and Strategy, Utility	May 2021 to December 2025
			Global Head of Utilities and Renewables, Bain & Company	March 2020 to April 2021
			Partner, Bain & Company	January 2014 to April 2021
Carla J. Peterman	47	PG&E Corporation	President, PG&E Corporation, and Executive Vice President, Customer and Corporate Affairs, PG&E Corporation	January 2026 to present
			Executive Vice President, Corporate Affairs and Chief Sustainability Officer, PG&E Corporation	October 2021 to December 2025
			Executive Vice President, Corporate Affairs, PG&E Corporation	June 2021 to September 2021
			Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison Company	September 2019 to May 2021
			Commissioner, California Public Utilities Commission	December 2012 to December 2018
---	---	---	---	---
Marlene M. Santos	65	PG&E Corporation,<br>Utility	Executive Vice President,<br>Enterprise Transformation Officer, PG&E Corporation and Utility	January 2026 to present
			Executive Vice President and Chief Customer and Enterprise Solutions Officer, Utility	October 2023 to December 2025
			Executive Vice President and Chief Customer Officer, Utility	March 2021 to October 2023
			President, Gulf Power Company	January 2019 to March 2021
John R. Simon	61	PG&E Corporation	Executive Vice President, General Counsel and Chief Ethics & Compliance Officer, PG&E Corporation	August 2020 to present
Sumeet Singh	47	PG&E Corporation,<br>Utility	Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery, Utility	January 2026 to present
			Executive Vice President, Operations and Chief Operating Officer, Utility	March 2023 to December 2025
			Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Utility	January 2022 to February 2023
			Senior Vice President and Chief Risk Officer, PG&E Corporation and Utility	February 2021 to December 2021
			Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation	January 2021 to January 2021
			Senior Vice President and Chief Risk Officer, PG&E Corporation and Utility	August 2020 to December 2021
Alejandro T. Vallejo	49	PG&E Corporation,<br>Utility	Executive Vice President, Chief People Officer, PG&E Corporation and Utility	September 2025 to present
			Chief Risk Officer and Senior Vice President, Ethics and Compliance, PG&E Corporation and Utility	August 2023 to September 2025
			Vice President, Compliance and Ethics, and Deputy General Counsel, Utility	December 2020 to July 2023
Ajay Waghray	64	PG&E Corporation,<br>Utility	Executive Vice President and Chief Information Officer, PG&E Corporation and Utility	January 2024 to present
			Executive Vice President and Chief Information Officer, PG&E Corporation	July 2023 to December 2023
			Senior Vice President and Chief Information Officer, PG&E Corporation	September 2020 to June 2023
Stephanie N. Williams	43	Utility	Vice President, Chief Financial Officer and Controller, Utility	January 2023 to present
Vice President and Controller, PG&E Corporation	January 2023 to present
---	---
Vice President, Finance and Planning, Utility	January 2020 to January 2023
Senior Director, Business Finance Electric Operations, Utility	March 2019 to December 2019

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

As of February 4, 2026, there were 38,490 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 2024 compared to 2023 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, 2024, which was filed with the SEC in February 2025.

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, the Continuation Account, and regulatory recovery.

In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, system hardening, situational awareness tools, and ignition response. These initiatives reduce but do not eliminate the Utility’s wildfire risk.

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

PG&E Corporation and the Utility have 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. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

The financial impact of past wildfires is significant. As of December 31, 2025, PG&E Corporation and the Utility have incurred significant liabilities for past wildfires (aggregate liability estimates of $1.325 billion for the 2019 Kincade fire, $2.15 billion for the 2021 Dixie fire, and $350 million for the 2022 Mosquito fire). These estimates do not include all categories of potential damages and 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, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8.

If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund or Continuation Account coverage year (“Coverage Year”), the Wildfire Fund or the Continuation Account, as applicable, may be available to reimburse the Utility such excess amount. The Utility’s ability to recover wildfire costs depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Wildfire Fund or the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable.

With respect to the Wildfire Fund, SCE has disclosed that a liability for the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”) is probable but not reasonably estimable. PG&E Corporation and the Utility expect to reduce their 20-year estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization based on reliable, publicly available information, including when and if SCE accrues a liability or a Wildfire Fund receivable, respectively (see Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8).

Recoveries for the 2019 Kincade fire are also 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 $1.150 billion for the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025.

With respect to the Continuation Account, additional uncertainties include whether the Wildfire Fund administrator determines that the Continuation Account is necessary, whether the CPUC authorizes extending the non-bypassable charge, whether the administrator determines that additional contributions are needed and, if so, the timing of those contingent contributions.

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 some or all of the expenses that it has recorded as receivables. As of December 31, 2025, the Utility has recorded receivables for regulatory recovery of $632 million for the 2021 Dixie fire and $61 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 Part II, Item 8 for more information.

•The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. 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). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. 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 Part II, Item 8, and “Regulatory Matters” below.

•There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition.

•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 intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results.

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 materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $38.3 billion and a California net operating loss carryforward of approximately $34.1 billion as of December 31, 2025.

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’s 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 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 PG&E Corporation’s 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 2,675,711,544 common shares outstanding as of February 4, 2026, only 2,197,967,954 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 4, 2026, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2026 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.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2025 and 2024.  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)	2025		2024		Net Change		Percentage Change
Consolidated Total	$	2,593	$	2,475	$	118	5	%
PG&E Corporation	(472)		(223)		(249)		112	%
Utility	3,065		2,698		367		14	%

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 2025 and 2024.  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. The line items with significant net changes are described below.

	Year Ended December 31,				Net Change (1)		Percentage Change
(in millions)	2025		2024
Electric operating revenues	$	18,318	$	17,811	$	507	3	%
Natural gas operating revenues	6,617		6,608		9		—	%
Total operating revenues	24,935		24,419		516		2	%
Cost of electricity	2,609		2,261		348		15	%
Cost of natural gas	1,107		1,192		(85)		(7)	%
Operating and maintenance	11,337		11,787		(450)		(4)	%
SB 901 securitization charges, net	35		33		2		6	%
Wildfire-related claims, net of recoveries	100		94		6		6	%
Wildfire Fund expense	352		383		(31)		(8)	%
Depreciation, amortization, and decommissioning	4,634		4,189		445		11	%
Total operating expenses	20,174		19,939		235		1	%
Operating income	4,761		4,480		281		6	%
Interest income	509		589		(80)		(14)	%
Interest expense	(2,713)		(2,781)		68		(2)	%
Other income, net	328		319		9		3	%
Income before income taxes	2,885		2,607		278		11	%
Income tax benefit	(194)		(105)		(89)		85	%
Net income	3,079		2,712		367		14	%
Preferred stock dividend requirement	14		14		—		—	%
Income Attributable to Common Stock	$	3,065	$	2,698	$	367	14	%

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $516 million, or 2%, in 2025 compared to 2024. The increase was primarily due to:

•approximately $650 million in revenues to recover the costs associated with extended operations at DCPP in 2025, with no comparable amount in 2024;

•approximately $500 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2025, as compared to 2024;

•approximately $380 million in revenue recognition authorized in the 2024 Transmission Revenue Requirement Reclassification Memo Account (“TRRRMA”) final decision in 2025, with no comparable amount in 2024; and

•$348 million in revenues to recover the cost of electricity procurement in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income,

partially offset by:

•approximately $540 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in 2024, with no comparable amount 2025;

•approximately $430 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K) in 2024, with no comparable amount in 2025;

•approximately $260 million less revenue recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below);

•approximately $120 million less in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in 2025, as compared to 2024; and

•$85 million less in revenues to recover the cost of natural gas in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income.

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 increased by $348 million in 2025 as compared to 2024. This increase was primarily the result of higher procurement costs, including local RA contract costs, FERC approved transmission owner rate case settlement costs, and higher nuclear fuel amortization, partially offset by increased CAISO market net sales, increased sales of various RPS resources, and lower net costs associated with fuel for utility owned generation and contracted generation.

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 $85 million in 2025 as compared to 2024. This decrease was primarily the result of lower GHG emission volumes, favorable price risk management activity resulting from reduced natural gas market volatility, and a reduction in contracted transport capacity, partially offset by higher natural gas procurement costs attributed to increased prices and demand, along with additional contracted storage capacity.

Operating and Maintenance

The Utility’s Operating and maintenance expense decreased by $450 million, or 4%, in 2025 compared to 2024. The decrease was primarily due to:

•approximately $560 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K) in 2024, with no comparable costs in 2025;

•approximately $540 million of previously deferred expenses authorized in the 2022 WMCE proceeding as part of interim rate relief (see “2022 WMCE Application” below) in 2024, with no comparable costs in 2025;

•approximately $260 million less expense recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below);

•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, with no comparable costs 2025; and

•approximately $150 million less expense recognized in 2025, as compared to 2024, authorized in the GOSMA petition for modification final decision,

partially offset by:

•approximately $570 million in costs associated with extended operations at DCPP in 2025, with no comparable costs in 2024;

•approximately $500 million more in previously deferred expenses in 2025, as compared to 2024, related to interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below); and

•approximately $150 million in previously deferred expenses related to VMBA disallowances in the 2023 WMCE final decision (see “2023 WMCE Application” below) in 2025, with no comparable costs in 2024.

Depreciation, Amortization, and Decommissioning

The Utility’s Depreciation, amortization, and decommissioning expenses increased by $445 million, or 11%, in 2025 compared to 2024. The increase was primarily due to the growth in plant balance from capital additions and the recognition of deferred depreciation expense.

Interest Income

The Utility’s Interest income decreased by $80 million, or 14%, in 2025 compared to 2024. The decrease was primarily due to a decrease in interest rates and a decrease in interest bearing account balances in 2025, compared to 2024.

Income Tax Benefit

The Utility’s Income tax benefit increased by $89 million, or 85%, in 2025 compared to 2024. The increase was primarily due to an increased tax repairs deduction and an additional deduction for certain costs attributable to electric generation.

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

	2025		2024
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)	(0.6)	%	(0.8)	%
Effect of regulatory treatment of fixed asset differences (2)	(27.4)	%	(25.2)	%
Nontaxable or nondeductible items	1.1	%	0.4	%
Tax credits	(0.9)	%	(0.9)	%
Changes in unrecognized tax benefits	0.1	%	1.9	%
Other, net	—	%	(0.4)	%
Effective tax rate	(6.7)	%	(4.0)	%

(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.

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.

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.

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 2031. 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 2026. See “Tax Matters” above 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 Part II, Item 8.

As of December 31, 2025, PG&E Corporation and the Utility had access to approximately $4.5 billion of total liquidity comprised of $353 million of the Utility’s Cash and cash equivalents, $360 million of PG&E Corporation’s Cash and cash equivalents, and $3.8 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 unsecured 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 unsecured credit rating remains below investment grade with one of the major credit rating agencies, 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. One financial covenant requires that the ratio of total consolidated debt to total consolidated capitalization as of the end of each fiscal quarter be no more than 70% for PG&E Corporation and 65% for the Utility.

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, 2025, PG&E Corporation and the Utility remain in compliance with all financial covenants.

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, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $360 million and $353 million, respectively.

Financial Resources

Equity Financings

PG&E Corporation does not expect to undertake any equity issuances through 2030. 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, the timing and terms of other financings, and the outcome of the Wildfire-Related Securities Claims. See “Wildfire-Related Securities Litigation” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8.

Debt Financings, Credit Facilities, and Term Loans

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

For more information, see “Credit Facilities and Term Loans” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8.

DOE Loan Guarantee Agreement

As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future.

For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K.

Other Financings

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 approvals.

Dividends

PG&E Corporation has announced a 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.

For information on dividend declarations and payments, see Notes 6 and 7 to the Consolidated Financial Statements in Part II, Item 8.

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 the year ended December 31, 2025 and 2024.

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2025		2024
Net cash provided by operating activities	$	9,035	$	8,268
Net cash used in investing activities	(12,316)		(11,375)
Net cash provided by financing activities	2,915		3,348
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	(366)	$	241

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities increased by $767 million, or 9%, in 2025 compared to 2024. This increase was primarily due to:

•an increase in collections driven in part by recoveries related to DCPP extended operations;

•a decrease in non-wildfire related insurance costs; and

•a decrease in wildfire-related payments, net of recoveries.

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 Recoveries under AB 1054 and SB 254” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8);

•the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 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 and natural gas 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 Part II, Item 8.

Investing Activities

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 following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2025, compared to December 31, 2024.

(in millions)	Year Ended December 31,
Cash used in investing activities - 2024	$	(11,375)
Capital expenditures	(1,418)
Net purchases related to customer credit trust investments	(186)
Net purchases related to self-insurance investment and other investing activities	663
Net increase in cash used in investing activities	(941)
Cash used in investing activities - 2025	$	(12,316)

Net cash used in investing activities increased by $0.9 billion, or 8%, in 2025 compared to 2024. This increase was primarily due to a $349 million payment for the purchase of the Oakland General Office, as discussed in Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8, along with higher investments in new business, capacity projects, and distribution system hardening. These increases were partially offset by lower funding related to self‑insurance investments in 2025 compared to 2024.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will invest $12.4 billion in capital expenditures in 2026.

Financing Activities

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.

The following table summarizes changes in key components of the Utility’s financing cash flows for the year ended December 31, 2025, compared to December 31, 2024.

(in millions)	Year Ended December 31,
Cash provided by financing activities - 2024	$	3,348
Net borrowings under credit facilities	6,574
Net borrowings under term loan	2,675
Repayments of long-term debt, net of proceeds	(1,113)
AB 1054 recovery bonds issuance	(1,409)
Short-term debt issuance	(1,999)
Dividend payments	(325)
Proceeds from DWR loan	(980)
Equity contributions from PG&E Corporation	(3,785)
Other financing activities	(71)
Net decrease in cash provided by financing activities	(433)
Cash provided by financing activities - 2025	$	2,915

Net cash provided by financing activities decreased by $433 million, or 13%, during the year ended December 31, 2025 as compared to the same period in 2024. The decrease was primarily due to:

•$3.8 billion decrease in equity contributions received from PG&E Corporation;

•$1.1 billion increase in repayments of long-term debt, net of proceeds;

•$2.7 billion decrease in net borrowings under term loan;

•$1.4 billion of proceeds related to the issuance of senior secured recovery bonds under the AB 1054 securitization in 2024, with no similar transaction in 2025;

•$2.0 billion decrease in proceeds related to short-term debt issuance;

•$980 million decrease in proceeds related to the DWR loan; and

•$325 million increase in dividend payments.

Partially offset by:

•$6.6 billion increase in net borrowings under credit facilities.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, 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 or outcome of the following proceedings.

Key updates to regulatory matters include the following:

•In February 2026, the CPUC issued a final decision in the Utility’s 2023 WMCE proceeding, approving recovery of $1.9 billion of costs.

•In February 2026, the OEIS issued a final decision approving the Utility’s 2026–2028 WMP. In December 2025, the Utility submitted its 2025 safety certificate request to OEIS.

•In December 2025, the CPUC issued a final decision in the Utility’s 2026 Cost of Capital proceeding that set the Utility’s ROE at 9.98% effective January 1, 2026 and approved a yield spread adjustment.

•In December 2025, the CPUC approved a resolution that updated CPUC guidelines for implementation of the SB 884 undergrounding program.

•In November 2025, the Utility filed the Kincade and Dixie AB 1054 Wildfire Cost Review and Recovery Proceeding application requesting recovery of approximately $1.59 billion of WEMA costs, review of costs drawn from the Wildfire Fund, and recovery of $314 million of CEMA costs.

•In August 2025, the FERC approved an all-party settlement in the Utility’s Transmission Owner Rate Case for 2024 (the “TO21” rate case).

•In August 2025, the CPUC issued a final decision that increases the cost cap for 2025 and 2026 by an aggregate $2.38 billion in connection with the Order Instituting Rulemaking (“OIR”) to Establish Energization Timelines.

•In September 2025, the CPUC issued a final decision approving $1.06 billion in cost recovery in the 2022 WMCE proceeding.

•In May 2025, the Utility filed its 2027 GRC application with the CPUC.

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 memorandum and balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, 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 Utility has recorded significant amounts to these accounts. 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, 2025, the Utility had recorded an aggregate amount of approximately $2.2 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, and WMBA, substantially all of which was accounted for as long term. See Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8.

If the amount of the costs recorded in these accounts increases, 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 Part II, Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below.

Key updates to the Utility’s cost recovery proceedings are summarized in the following table:

Proceeding	Request (1)	Status
2022 WMCE	$1.36 billion of cost recovery	Final decision authorizing $1.06 billion of total cost recovery issued September 2025.
2023 WMCE	$2.18 billion of cost recovery	Final decision authorizing $1.9 billion of costs issued February 2026.
2024 WMCE	$596 million of cost recovery	Application filed November 2024.
2023 WGSC	$2.5 billion of cost recovery	Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024.
Kincade and Dixie AB 1054	Review of 2019 Kincade fire and 2021 Dixie fire costs, including recovery of approximately $1.9 billion	Application filed November 2025.

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

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

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 the 2022 WMCE 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 consisted of $1.2 billion in expenses and $136 million in capital expenditures.

On September 26, 2025, the CPUC issued a final decision adopting the settlement agreement and authorizing total cost recovery for this matter of $1.06 billion. The final decision disallowed $217 million in VMBA costs.

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 the 2023 WMCE 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.

On February 5, 2026, the CPUC voted out a final decision, which approved recovery of $1.9 billion of costs. The final decision denied recovery of $173 million in vegetation management costs.

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 the 2024 WMCE 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 the 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 efforts 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.

On June 12, 2025, the CPUC issued a decision extending the statutory deadline in the proceeding from June 30, 2025 to March 31, 2026.

Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA.

The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as the Utility continues to resolve claims and draw from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 14 of the Notes to the Consolidated Financial Statements.

The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months.

Forward-Looking Rate Cases

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

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent 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.

Key updates to the Utility’s forward-looking rate cases are summarized in the following table:

Rate Case	Request	Status
2027 GRC	Revenue requirement of $16.64 billion for 2027	Filed May 2025. A PD is expected by March 2027 and a final decision by May 2027.
2026 Cost of Capital	Increase ROE to 11.30% and cost of debt to 5.04%	Final decision approving ROE of 9.98% and cost of debt of 5.04% issued December 2025.
Transmission Owner Rate Case for 2024 (TO21)	Revenue requirement of $2.78 billion for 2024, subject to true-up and refund	Accepted December 2023, except as to CAISO adder. All other issues resolved August 2025.

2027 General Rate Case

On May 15, 2025, the Utility filed its 2027 GRC application with the CPUC. In the 2027 GRC, the CPUC will determine the annual amount of revenue requirements that the Utility will be authorized to collect through rates from 2027 through 2030 to recover its anticipated costs for gas distribution, transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. On November 10, 2025, the Utility submitted errata to update its GRC opening testimony and revenue requirement request.

The table below compares the portion of CPUC jurisdictional revenue requirements and weighted-average rate base that are requested in the GRC proceeding, as updated, from 2027 through 2030 to the amounts adopted for 2026 in the 2023 GRC and other cost recovery proceedings:

Year	Requested revenue requirement (in billions)		Requested weighted-average GRC rate base
2026 (as adopted)	$	15.4	54.0
2027	16.6		67.0
2028	17.6		73.4
2029	18.7		79.4
2030	19.8		85.4

In the 2027 GRC application, the Utility proposed various safety, resiliency, and clean energy investments. Among other things, the Utility proposed to invest a total of approximately $45.0 billion between 2027 and 2030 in CPUC-jurisdictional assets. The proposed investments would support wildfire safety (including undergrounding 307 miles of electrical lines in 2027 and 400 miles per year for 2028 through 2030 until a 10-year undergrounding plan is approved), grid modernization, gas system safety, clean energy, and resilience.

In addition, the Utility requested authorization to establish new balancing accounts for new business capital spend and employee medical expenses.

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

On July 31, 2025, the CPUC issued a scoping memo that modifies the standard rate case plan schedule. The scoping memo indicates that the CPUC will issue a PD by March 2027 and a final decision by May 2027.

Cost of Capital Proceedings

2026 Cost of Capital Application

On March 20, 2025, the Utility (along with the other IOUs in California) submitted its 2026 Cost of Capital application.

On December 18, 2025, the CPUC issued a final decision and approved the following cost of capital rates, which went into effect beginning January 1, 2026:

	Cost	Weight	Weighted Cost
Return on Common Equity	9.98%	52.00%	5.19%
Return on Preferred Equity	5.52%	0.50%	0.03%
Return on Long-term debt	5.04%	47.50%	2.39%

The decision approved a revenue credit to return the benefit of potential DOE loan draws to customers and a temporary yield spread adjustment to compensate the Utility for its actual cost of short-term debt above the commercial paper rate. The yield spread adjustment for 2026 is 125 basis points. The decision also continued the Cost of Capital mechanism pursuant to which the Utility’s ROE will be adjusted and the cost of debt will be trued up to the most recent recorded cost of debt upon a significant change in rates.

Transmission Owner Rate Case for 2024

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 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 other California IOUs filed an appeal of the FERC’s order denying the Utility’s request for rehearing. On July 11, 2025, the Ninth Circuit Court of Appeals denied the utilities’ joint appeal. On August 20, 2025, the Utility and California IOUs sought en banc review from the Ninth Circuit. On September 15, 2025, the Ninth Circuit denied en banc review. On October 7, 2025, the Utility and California IOUs filed a petition for certiorari with the Supreme Court.

On March 21, 2025, the Utility filed with the FERC a settlement in the TO21 rate case. On August 5, 2025, the FERC issued a decision approving the settlement and resolving all contested issues in the proceeding, as well as specific wildfire cost recovery issues raised by stakeholders in prior proceedings related to the Utility’s TO tariff. The decision sets a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%.

On December 1, 2025, the Utility filed with the FERC the TO annual update for rate year 2026, which included the provisions of the TO21 settlement. The revenue requirement for rates that went into effect on January 1, 2026 is $2.6 billion, which represents a decrease from the 2025 revenue requirement of $2.9 billion.

Other Regulatory Proceedings

2026-2028 Wildfire Mitigation Plan

On April 4, 2025, the Utility submitted to the OEIS its 2026-2028 WMP, which it revised on July 28, 2025. The 2026-2028 WMP provides a comprehensive overview of the Utility’s wildfire mitigation strategy and incorporates lessons learned from previous years and emerging best practices. On February 5, 2026, the OEIS issued a final decision approving the Utility’s 2026–2028 WMP.

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 several California state agencies. As of December 31, 2025, the Utility has received all necessary state approvals except for approval from the Central Coast Region Water Quality Control Board. The CPUC’s 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 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. In June 2025, the NRC issued the final safety evaluation report and supplemental environmental impact statement.

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 addressed 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. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and SDGE requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing.

On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines.

LEGISLATIVE AND REGULATORY INITIATIVES

SB 254

On September 19, 2025, SB 254 became law and became effective. Among other things, the law provides for the Continuation Account, which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims incurred by large electric corporations (as defined in SB 254), if the Wildfire Fund is depleted. Each of California’s large electric IOUs has elected to participate in the Continuation Account. The Continuation Account would be similar to the Wildfire Fund, except:

•The Continuation Account would provide up to $18 billion of liquidity. If the Wildfire Fund administrator determines that the Continuation Account is necessary prior to December 31, 2028, the CPUC will consider whether to extend the non-bypassable charge on customers from 2036 through 2045. If the CPUC extends the non-bypassable charge on customers, the participating utilities’ annual $300 million contributions will be extended from 2029 through 2045.

The Wildfire Fund administrator is also authorized to determine if additional annual contributions are needed, in which case the participating utilities will contribute an additional $3.9 billion in equal installment payments over five years. If the administrator winds up and terminates the Continuation Account before the final installment payment is made, the utilities will return one-half of the unpaid installment payments as rate credits to customers.

The Utility’s allocation among the participating utilities for these contributions is 47.85%.

•If a utility is required to reimburse the Continuation Account, the amount of reimbursement will be reduced by the amount of contributions for which the utility has not claimed a reduction.

•The disallowance cap on reimbursements, which is equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base, is determined based on the year of the ignition. This revised disallowance cap applies to fires occurring before or after the effective date of SB 254.

Assets in the Continuation Account are separate from the Wildfire Fund and are not available for fires ignited before the effective date of SB 254.

For fires that destroy 1,000 or more structures, SB 254 gives the participating utilities a right of first refusal over insurers’ transactions to sell their right of subrogation, reimbursement, or recovery.

SB 254 also prohibits the Utility from including in its equity rate base the first $2.9 billion that it first expends on fire risk mitigation capital expenditures approved by the CPUC on or after January 1, 2026. The Utility expects to finance this amount with securitization.

SB 254 requires the Wildfire Fund administrator to prepare a report by April 1, 2026 that evaluates and sets forth recommendations on new models or approaches that mitigate damage, accelerate recovery, and responsibly and equitably allocate the burdens from natural catastrophes, including catastrophic wildfires, earthquakes, and other natural disasters, across stakeholders, including insurers, communities, homeowners, landowners, governments, large electrical corporations, and local publicly owned electric utilities, to complement or replace the Wildfire Fund.

LITIGATION AND OTHER MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 and in “Regulatory Matters” above 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.

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 $4 million and $5 million at December 31, 2025 and 2024, 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, 2025 and 2024, 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 $37 million and $6 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry 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<br>Wholesale<br>Customers or<br>Counterparties<br>>10%	Net Credit<br>Exposure to<br>Wholesale<br>Customers or<br>Counterparties<br>>10% <br>(in millions)
December 31, 2025	$	1,048	4	$	714
December 31, 2024	$	1,114	4	$	708

(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.

Contributions to the Wildfire Fund

PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the longevity of the fund, PG&E Corporation and the Utility use a dataset with historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The simulation began with 12 years of publicly available fire-loss data, and PG&E Corporation and the Utility add an additional year of data each subsequent year. In addition to historical data, significant assumptions also include the estimated amount of Wildfire Fund claim payments, the number of years of fire-loss data, estimated costs of wildfire settlement claims from other participating utilities, CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and the amounts required to be reimbursed to the Wildfire Fund, and the effects of climate change. Due to the significant judgment required to estimate the life of the Wildfire Fund, there is a high degree of uncertainty for many of these assumptions, and so subsequent changes to the available information could materially impact the remaining estimated life of the fund. Based upon the outcome of newly run Monte Carlo simulations when known information becomes available, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. For instance, in 2024, a re-evaluation in the estimate resulted in the Wildfire Fund life increasing from 15 to 20 years.

Estimates for the useful life of the Wildfire Fund and the accelerated amortization of the fund, respectively, are based on a variety of assumptions and are subject to uncertainty and change as additional information becomes publicly available. The estimated life of the Wildfire Fund reflects wildfire risk in the state, while accelerated amortization anticipates potential draw-downs of the Wildfire Fund. Both of these estimates have a high degree of uncertainty since they rely on a number of assumptions, such as potential wildfire claim payments, future wildfire activity, regulatory decisions, and any potential disclosed cost of wildfires caused by other participating electric utilities.

SCE has disclosed that a liability for the Eaton fire is probable but not reasonably estimable. PG&E Corporation and the Utility expect to reduce their 20-year estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization based on reliable, publicly available information, including when and if SCE accrues a liability or a Wildfire Fund receivable, respectively. As a result, the Wildfire Fund asset could be amortized down to zero in the near future. For every $5 billion of Wildfire Fund receivables recorded by a participating utility, PG&E Corporation and the Utility expect that they would record approximately $1 billion of accelerated amortization.

As of December 31, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $377 million in Other noncurrent liabilities, $297 million in Current assets - Wildfire Fund asset, and $3.7 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $352 million and $383 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.

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 Monte Carlo 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, 2025, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by ten 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.

For more information, see “Contributions to the Wildfire Fund and the Continuation Account” in Note 2 and “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Contingencies

PG&E Corporation and the Utility record an estimated liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. As discussed below, PG&E Corporation and the Utility have recorded material estimated liabilities for various wildfire-related, enforcement, environmental remediation, and other legal matters. For more information about PG&E Corporation’s and the Utility’s accounting policies and sources of uncertainty in these estimates, see Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8.

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.

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. The process for estimating liabilities requires management to exercise significant judgment 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. As more information becomes available, including from potential claimants as litigation or resolutions progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change.

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.

With respect to environmental remediation, as of December 31, 2025 and 2024, the Utility’s estimated undiscounted gross environmental liabilities were $1.2 billion each. The Utility’s undiscounted future costs could increase to as much as $2.2 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.

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.

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. 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, 2025, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $22.6 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $24.3 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, 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. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC.

Additionally, SB 901 provides a mechanism for the CPUC to 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, 2025, the SB 901 regulatory asset was approximately $5.1 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, escalation rates, credit-adjusted risk-free rates, and estimated decommissioning dates. 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. 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.

At December 31, 2025, 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.

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 2026 was 7.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2036 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 7.0% compares to a ten-year actual return of 5.7%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 831 Aa-grade non-callable bonds at December 31, 2025. 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<br>(Decrease) in<br>Assumption		Increase in 2025 Pension<br><br>Costs		Increase in Projected<br><br>Benefit Obligation at<br><br>December 31, 2025
Discount rate	(0.50)	%	$	13	$	1,148
Rate of return on plan assets	(0.50)	%	82		—
Rate of increase in compensation	0.50	%	35		267

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

(in millions)	Increase<br>(Decrease) in<br>Assumption		Increase in 2025<br><br>Other Postretirement<br><br>Benefit Costs		Increase in Accumulated<br><br>Benefit Obligation at<br><br>December 31, 2025
Health care cost trend rate	0.50	%	$	6	$	41
Discount rate	(0.50)	%	6		89
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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2025		2024		2023
Operating Revenues
Electric	$	18,318	$	17,811	$	17,424
Natural gas	6,617		6,608		7,004
Total operating revenues	24,935		24,419		24,428
Operating Expenses
Cost of electricity	2,609		2,261		2,443
Cost of natural gas	1,107		1,192		1,754
Operating and maintenance	11,349		11,808		11,924
SB 901 securitization charges, net	35		33		1,267
Wildfire-related claims, net of recoveries	100		94		64
Wildfire Fund expense	352		383		567
Depreciation, amortization, and decommissioning	4,634		4,189		3,738
Total operating expenses	20,186		19,960		21,757
Operating Income	4,749		4,459		2,671
Interest income	520		604		606
Interest expense	(3,028)		(3,051)		(2,850)
Other income, net	182		300		272
Income Before Income Taxes	2,423		2,312		699
Income tax benefit	(280)		(200)		(1,557)
Net Income	2,703		2,512		2,256
Preferred stock dividend requirement	110		37		14
Income Available for Common Shareholders	$	2,593	$	2,475	$	2,242
Weighted Average Common Shares Outstanding, Basic	2,197		2,141		2,064
Weighted Average Common Shares Outstanding, Diluted	2,202		2,147		2,138
Net Income Per Common Share, Basic	$	1.18	$	1.16	$	1.09
Net Income Per Common Share, Diluted	$	1.18	$	1.15	$	1.05

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2025		2024		2023
Net Income	$	2,703	$	2,512	$	2,256
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively)	(11)		(7)		(16)
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $3, respectively)	5		1		8
Total other comprehensive income (loss)	(6)		(6)		(8)
Comprehensive Income	2,697		2,506		2,248
Preferred stock dividend requirement	110		37		14
Comprehensive Income Attributable to Common Shareholders	$	2,587	$	2,469	$	2,234

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at
	December 31, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	713	$	940
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates)	259		273
Accounts receivable
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates)<br><br>(includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates)	2,267		2,220
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates)	1,463		1,487
Regulatory balancing accounts	6,300		7,227
Other (net of allowance for doubtful accounts of $69 million and $35 million at respective dates)	1,719		1,810
Regulatory assets	305		234
Inventories
Gas stored underground and fuel oil	75		52
Materials and supplies	745		768
Wildfire Fund asset	297		301
Wildfire self-insurance asset	1,043		905
Other	644		999
Total current assets	15,830		17,216
Property, Plant, and Equipment
Property, Plant, and Equipment	128,989		118,262
Construction work in progress	4,627		4,458
Financing lease ROU asset and other	2		814
Total property, plant, and equipment	133,618		123,534
Accumulated depreciation	(37,270)		(35,305)
Net property, plant, and equipment	96,348		88,229
Other Noncurrent Assets
Regulatory assets	15,981		15,561
Customer credit trust	804		377
Nuclear decommissioning trusts	4,230		3,833
Operating lease ROU asset	450		524
Wildfire Fund asset	3,728		4,070
Other (includes noncurrent accounts receivable of $67 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $18 at respective dates)	4,240		3,850
Total other noncurrent assets	29,433		28,215
TOTAL ASSETS	$	141,611	$	133,660

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at
	December 31, 2025		December 31, 2024
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,675	$	1,523
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates)	821		2,146
Accounts payable
Trade creditors	3,353		2,748
Regulatory balancing accounts	3,119		3,169
Other	929		748
Operating lease liabilities	90		85
Financing lease liabilities	—		577
Interest payable (includes $72 million and $91 million related to VIEs at respective dates)	764		760
Wildfire-related claims	524		916
Other	4,025		3,658
Total current liabilities	16,300		16,330
Noncurrent Liabilities
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates)	57,387		53,569
Regulatory liabilities	20,188		19,417
Pension and other postretirement benefits	549		808
Asset retirement obligations	5,439		5,444
Deferred income taxes	4,135		3,082
Operating lease liabilities	360		439
Financing lease liabilities	2		4
Other	4,459		4,166
Total noncurrent liabilities	92,519		86,929
Equity
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		1,579
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,197,942,874 and 2,193,573,536 shares outstanding at respective dates	31,636		31,555
Reinvested earnings	(650)		(2,966)
Accumulated other comprehensive loss	(25)		(19)
Total shareholders’ equity	32,540		30,149
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	32,792		30,401
TOTAL LIABILITIES AND EQUITY	$	141,611	$	133,660

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2025		2024		2023
Cash Flows from Operating Activities
Net income	$	2,703	$	2,512	$	2,256
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,634		4,189		3,738
Bad debt expense	402		341		636
Allowance for equity funds used during construction	(219)		(184)		(179)
Deferred income taxes and tax credits, net	1,058		1,098		(765)
Wildfire Fund expense	352		383		568
Other	(75)		310		(116)
Effect of changes in operating assets and liabilities:
Accounts receivable	(61)		(1,061)		(369)
Wildfire-related insurance receivable	(167)		318		358
Inventories	—		45		(28)
Accounts payable	176		30		(90)
Wildfire-related claims	(392)		(506)		(489)
Other current assets and liabilities	563		(231)		397
Regulatory assets, liabilities, and balancing accounts, net	173		1,545		(429)
Contributions to Wildfire Fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(238)		(561)		(548)
Net cash provided by operating activities	8,716		8,035		4,747
Cash Flows from Investing Activities
Capital expenditures	(11,787)		(10,369)		(9,714)
Proceeds from sales and maturities of nuclear decommissioning trust <br>   investments	1,952		1,980		2,235
Purchases of nuclear decommissioning trust investments	(1,993)		(2,002)		(2,252)
Proceeds from sales and maturities of customer credit trust investments	435		398		556
Purchases of customer credit trust investments	(742)		(519)		—
Proceeds from sales and maturities of self-insurance investments	1,181		—		—
Purchases of self-insurance investments	(1,384)		(898)		—
Other	22		35		13
Net cash used in investing activities	(12,316)		(11,375)		(9,162)
Cash Flows from Financing Activities
Borrowings under credit facilities	4,790		6,873		10,675
Repayments under credit facilities	(1,465)		(10,122)		(10,540)
Borrowings under term loan	575		—		2,100
Repayments under term loan	—		(2,600)		(2,181)
Short-term debt financing, net of issuance costs of $0, $1, and $0 at<br><br>respective dates	—		999		—
Short-term debt matured	(1,000)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and<br><br>issuance costs of $38, $5, and $67 at respective dates	4,962		4,495		5,483
Repayment of long-term debt	(3,876)		(800)		(3,075)
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees<br><br>of $0, $10 and $0 at respective dates	—		1,409		—
---	---	---	---	---	---	---
Repayment of AB 1054 recovery bonds	(88)		(46)		(38)
Repayment of SB 901 recovery bonds	(135)		(129)		(130)
Proceeds from DWR loan	—		980		—
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $0, and $27 at respective dates	—		—		2,123
Common stock issued	—		1,128		—
Mandatory convertible preferred stock issued	—		1,579		—
Common stock dividends paid	(220)		(86)		—
Mandatory convertible preferred stock dividends paid	(97)		—		—
Other	(87)		(59)		(17)
Net cash provided by financing activities	3,359		3,621		4,400
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	(241)		281		(15)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	1,213		932		947
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	972	$	1,213	$	932
Less: Restricted cash and restricted cash equivalents	(259)		(273)		(297)
Cash and cash equivalents at December 31	$	713	$	940	$	635
Supplemental disclosures of cash flow information
---	---	---	---	---	---	---
Cash paid for:
Interest, net of amounts capitalized	$	(2,665)	$	(2,421)	$	(2,286)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,859	$	1,144	$	1,105
Operating lease liabilities arising from obtaining ROU assets	—		6		269
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	148		192		214
Changes to PG&E Corporation common stock and treasury stock in <br>   connection with share exchanges with the Fire Victim Trust	—		—		(2,517)
Common stock dividends declared but not yet paid	111		55		21
Mandatory convertible preferred stock dividends declared but not yet paid	23		23		—
Capital expenditures financed through current assets and non-current liabilities	592		—		—

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Preferred Stock			Common Stock					Treasury Stock				Reinvested<br>Earnings		Accumulated<br>Other<br>Comprehensive Income<br>(Loss)		Total<br>Shareholders'<br>Equity		Non-<br>controlling<br>Interest -<br>Preferred<br>Stock  of<br>Subsidiary		Total<br>Equity
			Shares		Amount			Shares		Amount
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
Net income	—			—		—			—		—		2,703		—		2,703		—		2,703
Other comprehensive loss	—			—		—			—		—		—		(6)		(6)		—		(6)
Common stock issued, net	—			4,369,338		(1)			—		—		—		—		(1)		—		(1)
Stock-based compensation amortization	—			—		82			—		—		—		—		82		—		82
Common stock dividends declared	—			—		—			—		—		(277)		—		(277)		—		(277)
Preferred stock dividend requirement	—			—		—			—		—		(110)		—		(110)		—		(110)
Balance at December 31, 2025	$	1,579		2,197,942,874		$	31,636		—		$	—	$	(650)	$	(25)	$	32,540	$	252	$	32,792

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2025		2024		2023
Operating Revenues
Electric	$	18,318	$	17,811	$	17,424
Natural gas	6,617		6,608		7,004
Total operating revenues	24,935		24,419		24,428
Operating Expenses
Cost of electricity	2,609		2,261		2,443
Cost of natural gas	1,107		1,192		1,754
Operating and maintenance	11,337		11,787		11,913
SB 901 securitization charges, net	35		33		1,267
Wildfire-related claims, net of recoveries	100		94		64
Wildfire Fund expense	352		383		567
Depreciation, amortization, and decommissioning	4,634		4,189		3,738
Total operating expenses	20,174		19,939		21,746
Operating Income	4,761		4,480		2,682
Interest income	509		589		593
Interest expense	(2,713)		(2,781)		(2,485)
Other income, net	328		319		293
Income Before Income Taxes	2,885		2,607		1,083
Income tax benefit	(194)		(105)		(1,461)
Net Income	3,079		2,712		2,544
Preferred stock dividend requirement	14		14		14
Income Available for Common Stock	$	3,065	$	2,698	$	2,530

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2025		2024		2023
Net Income	$	3,079	$	2,712	$	2,544
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $$5, respectively)	(8)		(8)		(12)
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $4, respectively)	5		1		7
Total other comprehensive income (loss)	(3)		(7)		(5)
Comprehensive Income	$	3,076	$	2,705	$	2,539

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at
	December 31, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	353	$	705
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates)	258		272
Accounts receivable
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates)	2,267		2,220
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates)	1,463		1,487
Regulatory balancing accounts	6,300		7,227
Other (net of allowance for doubtful accounts of $69 million and $35 million at respective dates)	1,725		1,810
Regulatory assets	305		234
Inventories
Gas stored underground and fuel oil	75		52
Materials and supplies	745		768
Wildfire Fund asset	297		301
Wildfire self-insurance asset	1,043		905
Other	643		998
Total current assets	15,474		16,979
Property, Plant, and Equipment
Property, Plant, and Equipment	128,989		118,262
Construction work in progress	4,626		4,458
Financing lease ROU asset and other	2		814
Total property, plant, and equipment	133,617		123,534
Accumulated depreciation	(37,269)		(35,304)
Net property, plant, and equipment	96,348		88,230
Other Noncurrent Assets
Regulatory assets	15,981		15,561
Customer credit trust	804		377
Nuclear decommissioning trusts	4,230		3,833
Operating lease ROU asset	445		519
Wildfire Fund asset	3,728		4,070
Other (includes noncurrent accounts receivable of $67 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $18 at respective dates)	4,073		3,697
Total other noncurrent assets	29,261		28,057
TOTAL ASSETS	$	141,083	$	133,266

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at
	December 31, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	2,675	$	1,523
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates)	821		2,146
Accounts payable
Trade creditors	3,352		2,745
Regulatory balancing accounts	3,119		3,169
Other	844		729
Operating lease liabilities	90		85
Financing lease liabilities	—		577
Interest payable (includes $72 million and $91 million related to VIEs at respective dates)	673		667
Wildfire-related claims	524		916
Other	3,710		3,331
Total current liabilities	15,808		15,888
Noncurrent Liabilities
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates)	51,766		47,958
Regulatory liabilities	20,188		19,417
Pension and other postretirement benefits	482		741
Asset retirement obligations	5,439		5,444
Deferred income taxes	4,732		3,632
Operating lease liabilities	355		434
Financing lease liabilities	2		4
Other	4,474		4,198
Total noncurrent liabilities	87,438		81,828
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	37,505		35,930
Reinvested earnings	(1,225)		(1,940)
Accumulated other comprehensive loss	(23)		(20)
Total shareholders’ equity	37,837		35,550
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	141,083	$	133,266

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2025		2024		2023
Cash Flows from Operating Activities
Net income	$	3,079	$	2,712	$	2,544
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	4,634		4,189		3,738
Bad debt expense	402		341		636
Allowance for equity funds used during construction	(219)		(184)		(179)
Deferred income taxes and tax credits, net	1,102		1,195		(663)
Wildfire Fund expense	352		383		568
Other	(158)		233		(176)
Effect of changes in operating assets and liabilities:
Accounts receivable	(67)		(1,060)		(361)
Wildfire-related insurance receivable	(167)		318		358
Inventories	—		45		(28)
Accounts payable	112		44		(90)
Wildfire-related claims	(392)		(506)		(489)
Other current assets and liabilities	617		(235)		402
Regulatory assets, liabilities, and balancing accounts, net	173		1,545		(429)
Contributions to Wildfire Fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(240)		(559)		(541)
Net cash provided by operating activities	9,035		8,268		5,097
Cash Flows from Investing Activities
Capital expenditures	(11,787)		(10,369)		(9,714)
Proceeds from sales and maturities of nuclear decommissioning trust <br>   investments	1,952		1,980		2,235
Purchases of nuclear decommissioning trust investments	(1,993)		(2,002)		(2,252)
Proceeds from sales and maturities of customer credit trust investments	435		398		556
Purchases of customer credit investments	(742)		(519)		—
Proceeds from sales and maturities of self-insurance investments	1,181		—		—
Purchases of self-insurance investments	(1,384)		(898)		—
Other	22		35		13
Net cash used in investing activities	(12,316)		(11,375)		(9,162)
Cash Flows from Financing Activities
Borrowings under credit facilities	4,790		6,873		10,675
Repayments under credit facilities	(1,465)		(10,122)		(10,540)
Borrowings under term loan	575		—		2,100
Repayments under term loan	—		(2,100)		—
Short-term debt financing, net of issuance costs of $0, $1, and $0 at respective dates	—		999		—
Short-term debt matured	(1,000)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and<br><br>issuance costs of $38, $1, and $67 at respective dates	4,962		2,999		5,483
Repayment of long-term debt	(3,876)		(800)		(3,075)
Proceeds from AB 1054 recovery bonds, net issuance costs of $0, $10, and $0 at respective dates	—		1,409		—
---	---	---	---	---	---	---
Repayment of AB 1054 recovery bonds	(88)		(46)		(38)
Repayment of SB 901 recovery bonds	(135)		(129)		(130)
Proceeds from DWR loan	—		980		—
Preferred stock dividends paid	(14)		(14)		(14)
Common stock dividends paid	(2,350)		(2,025)		(1,775)
Equity contribution from PG&E Corporation	1,575		5,360		1,290
Other	(59)		(36)		3
Net cash provided by financing activities	2,915		3,348		3,979
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	(366)		241		(86)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	977		736		822
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	611	$	977	$	736
Less: Restricted cash and restricted cash equivalents	(258)		(272)		(294)
Cash and cash equivalents at December 31	$	353	$	705	$	442
Supplemental disclosures of cash flow information
---	---	---	---	---	---	---
Cash paid for:
Interest, net of amounts capitalized	$	(2,359)	$	(2,206)	$	(1,977)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,859	$	1,144	$	1,105
Operating lease liabilities arising from obtaining ROU assets	—		1		269
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	148		192		214
Capital expenditures financed through current assets and non-current liabilities	592		—		—

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

	Preferred<br>Stock		Common<br>Stock		Additional<br>Paid-in<br>Capital		Reinvested<br>Earnings		Accumulated<br>Other<br>Comprehensive<br>Income (Loss)		Total<br>Shareholders'<br>Equity
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 loss	—		—		—		—		(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
Net income	—		—		—		3,079		—		3,079
Other comprehensive loss	—		—		—		—		(3)		(3)
Equity contribution	—		—		1,575		—		—		1,575
Preferred stock dividend requirement	—		—		—		(14)		—		(14)
Common stock dividend	—		—		—		(2,350)		—		(2,350)
Balance at December 31, 2025	$	258	$	1,322	$	37,505	$	(1,225)	$	(23)	$	37,837

See accompanying Notes to the Consolidated Financial Statements.

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.

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, 2025 and 2024, the Utility also held $258 million and $272 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.

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)	2025		2024		2023
Electric
Revenue from contracts with customers
Residential	$	6,976	$	7,504	$	6,041
Commercial	7,022		7,201		5,643
Industrial	1,929		2,065		1,784
Agricultural	1,825		1,815		1,413
Public street and highway lighting	105		103		83
Other, net (1)	72		(47)		136
Total revenue from contracts with customers - electric	17,929		18,641		15,100
Regulatory balancing accounts (2)	389		(830)		2,324
Total electric operating revenue	$	18,318	$	17,811	$	17,424
Natural gas
Revenue from contracts with customers
Residential	$	3,651	$	3,089	$	3,686
Commercial	1,074		984		1,052
Transportation service only	1,937		1,815		1,603
Other, net (1)	101		159		(145)
Total revenue from contracts with customers - gas	6,763		6,047		6,196
Regulatory balancing accounts (2)	(146)		561		808
Total natural gas operating revenue	6,617		6,608		7,004
Total operating revenues	$	24,935	$	24,419	$	24,428

(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, 2025, PG&E Corporation and the Utility have 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 using an analysis of regional unemployment rates.

Expected credit losses of $402 million, $341 million, and $636 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, 2025, 2024, and 2023, 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, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. 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. For certain investments held by PG&E Corporation and the Utility, the companies 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, 2025, 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)	2025		2024
Electricity generating facilities (1)	1 to 75	$	11,986	$	11,420
Electricity distribution facilities	5 to 70	57,174		49,821
Electricity transmission facilities	5 to 80	20,959		18,481
Natural gas distribution facilities	15 to 60	18,240		17,213
Natural gas transmission and storage facilities	15 to 68	11,315		11,117
General plant and other	5 to 50	9,315		10,210
Financing lease		2		814
Construction work in progress		4,626		4,458
Total property, plant, and equipment		133,617		123,534
Accumulated depreciation		(37,269)		(35,304)
Net property, plant, and equipment (2)		$	96,348	$	88,230

(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. See Note 15 below. Nuclear generating facilities have been fully depreciated by December 31, 2025.

(2) Includes $2.9 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 3.77% in 2025 and 3.61% in 2024. 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 asset 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 $88 million and $219 million during 2025, $111 million and $184 million during 2024, and $82 million and $179 million during 2023.

Asset Retirement Obligations

The following table summarizes the changes in ARO during 2025 and 2024, including nuclear decommissioning obligations:

(in millions)	2025		2024
ARO liability at beginning of year	$	5,444	$	5,512
Revision in estimated cash flows	(274)		(290)
Accretion	290		269
Liabilities settled	(21)		(47)
ARO liability at end of year	$	5,439	$	5,444

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; removal of hazardous materials in some gas transmission assets and restoration of land to the conditions under certain agreements.

The total nuclear decommissioning obligation was $4.2 billion as of December 31, 2025 and $4.0 billion as of December 31, 2024 based on the cost study performed as part of the 2021 NDCTP. The Utility’s ARO assumes that DCPP operates until 2030. The 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 recognizes a loss 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.

The cost of debt and equity securities sold by the trust is determined by specific identification. Gains on the nuclear decommissioning trust investments are refundable to customers through rates, and losses are recoverable 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.

Government Assistance

The Utility participated in various government assistance programs during the year ended December 31, 2025, 2024, and 2023. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

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, 2025, the Consolidated Statements of Income reflected $13 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. 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 entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final proceeds were received in 2024, and no further disbursements will be made.

The Utility initially accounted 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)	2025		2024		2023
Long-term debt:
Beginning Balance - DWR loan outstanding	$	886	$	98	$	312
Proceeds received	—		980		—
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(21)		(117)		(124)
Operating and maintenance expense - Loan forgiveness and other adjustments	(127)		(75)		(90)
Long-term debt:
Ending Balance - DWR loan outstanding	$	738	$	886	$	98

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and the 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, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $65 million, $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, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $69 million, $138 million, and $76 million, respectively, as deductions 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 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, 2025 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2025 and December 31, 2024, the SPV had net accounts receivable of $3.2 billion, and outstanding borrowings of $1.8 billion and $0 million, 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, 2025 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Recovery Funding LLC had outstanding borrowings of $3.1 billion and $3.2 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, 2025 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate $7.5 billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion and $7.2 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, 2025, 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, 2025, it did not consolidate any of them.

Contributions to the Wildfire Fund and the Continuation Account

AB 1054 did not specify a period of coverage for the Wildfire Fund, and so the accounting treatment is subject to significant judgments and estimates. PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below.

In estimating the life of the fund, PG&E Corporation and the Utility use a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. PG&E Corporation’s and the Utility’s initial estimated life of the fund was 15 years. In 2024, a re-evaluation resulted in the estimated life increasing from 15 to 20 years.

The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include 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. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

PG&E Corporation and the Utility have an established process to re-evaluate the estimated life of the fund whenever they obtain new significant fire-loss data. PG&E Corporation and the Utility consider significant fire-loss data to include Cal Fire’s annual release of the prior year’s fire-loss data, internally developed data about wildfires and wildfire conditions in their own service area, and other participating electric utilities’ public disclosures of probable and estimable wildfire-related losses in their service area. PG&E Corporation and the Utility are not able to independently verify other utilities’ estimates. During each re-evaluation, PG&E Corporation and the Utility update their assumptions and the dataset of historical fire-losses for wildfires caused by electrical equipment, as applicable. Based upon the outcome of the newly run Monte Carlo simulations, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. PG&E Corporation and the Utility apply adjustments to the estimated life of the fund on a prospective basis.

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable.

As of December 31, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $377 million in Other noncurrent liabilities, $297 million in Current assets - Wildfire Fund asset, and $3.7 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $352 million and $383 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.

PG&E Corporation and the Utility expect to begin accounting for the Continuation Account if the Wildfire Fund administrator determines that the Continuation Account is necessary and the CPUC approves the extension of non-bypassable charges to customers.

For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 below.

Oakland Headquarters Purchase

On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Oakland General Office. The purchase price was $906 million, of which the Utility had prepaid a total of $400 million. At closing, the Utility assumed a $172 million noncurrent liability for a property assessment carried by the property and paid an additional $349 million, which was adjusted for closing costs. The cash payment is included within the Capital expenditures line item in PG&E Corporation’s and Utility’s Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities.

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, 2025 consisted of the following:

(in millions, net of income tax)	Pension<br>Benefits		Other<br>Benefits		Available-for-Sale Securities(2)		Total
Beginning balance	$	(35)	$	18	$	3	$	(14)
Other comprehensive income before reclassifications:
Unrealized loss on investments (net of taxes of $0, $0 and $2, respectively)	—		—		5		5
Unrecognized net actuarial gain (loss) (net of taxes of $84, $25 and $0, respectively)	215		(64)		—		151
Regulatory account transfer (net of taxes of $89, $25 and $0, respectively)	(228)		64		—		(164)
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 $1, $6 and $0, respectively) (1)	1		(15)		—		(14)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)	2		14		—		16
Net current period other comprehensive income	(12)		1		5		(6)
Ending balance	$	(47)	$	19	$	8	$	(20)

(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 self-insurance.

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<br>Benefits		Other<br>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 (loss)	(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 wildfire self-insurance.

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, 2025, 2024 and 2023, the Utility made total fixed cash payments of $26 million, $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. 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 related to the lease of the Oakland General Office, which the Utility purchased on June 3, 2025. See “Oakland Headquarters Purchase” above.

At December 31, 2025 and 2024, the Utility’s financing leases had a weighted average remaining lease term of 4.1 years and 0.5 years and a weighted average discount rate of 4.6% and 6.2%, 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)	2025		2024		2023
Financing lease fixed cost:
Amortization of ROU assets	$	583	$	274	$	115
Interest on lease liabilities	16		42		27
Financing lease variable cost	(1)		9		3
Total financing lease costs	$	598	$	325	$	145

As of December 31, 2025, the Utility’s future expected financing lease payments are not material.

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, 2025, 2024, and 2023, the Utility made total cash payments, including fixed and variable, of $1.6 billion, $1.6 billion, and $1.9 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, 2025 and 2024, the Utility’s operating leases had a weighted average remaining lease term of 7.1 years and 7.5 years and a weighted average discount rate of 6.6% 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)	2025		2024		2023
Operating lease fixed cost	$	115	$	116	$	269
Operating lease variable cost	1,487		1,524		1,632
Total operating lease costs	$	1,602	$	1,640	$	1,901

At December 31, 2025, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2025
2026	$	115
2027	112
2028	98
2029	64
2030	34
Thereafter	165
Total lease payments	588
Less imputed interest	(143)
Total	$	445

Recently Adopted Accounting Standards

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amended the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. PG&E Corporation and the Utility have applied enhanced disclosure requirements, including, but not limited to, those with respect to PG&E Corporation and the Utility’s income tax rate reconciliation and income taxes paid. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025 and PG&E Corporation and the Utility have applied the enhanced disclosure requirements of ASU 2023-09 on a retrospective basis.

Derivatives and Hedging and Revenue from Contracts with Customers

In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606), which amended the existing guidance to (a) reduce the cost and complexity of evaluating whether contracts with features based on the operations or activities of one of the parties to the contract are derivatives, (b) better portray the economics of those contracts in the financial statements, and (c) reduce diversity in practice resulting from the broad application of the current guidance and changing business environment. The amendments also are expected to reduce diversity in practice by clarifying the applicability of Topic 606, Revenue from Contracts with Customers, to share-based noncash consideration from a customer for the transfer of goods or services. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2025. The adoption of this ASU did not have a significant impact on PG&E Corporation and the Utility’s Consolidated Financial Statements and related disclosures.

Accounting Standards Issued But Not Yet Adopted

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 amended 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 amended 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.

Intangibles – Goodwill and Other – Internal Use Software

In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40), which amended the existing guidance to modernize the accounting for software costs that are accounted for under Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this ASU remove all references to prescriptive and sequential software development stages throughout Subtopic 350-40. Therefore, an entity is required to start capitalizing software costs when both of the following occur: (1) management has authorized and committed to funding the software project, and (2) it is probable that the project will be completed, and the software will be used to perform the function. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, 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.

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<br>Period
(in millions)	2025		2024
Pension benefits (1)	$	400	$	673	Indefinitely
Environmental compliance costs	1,158		1,172		32 years
Price risk management	100		167		up to 15.5 years
Catastrophic event memorandum account (2)	666		742		Various
Wildfire-related accounts (3)	1,626		1,697		Various
Deferred income taxes (4)	6,157		4,771		Various
Financing costs (5)	202		216		Various
SB 901 securitization (6)	5,089		5,194		27 years
General rate case memorandum accounts (7)	—		95		Various
Other (8)	583		834		Various
Total noncurrent regulatory assets	$	15,981	$	15,561

(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.

(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, 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 included 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.

(8) The balance as of December 31, 2025 includes revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2025 and 2024, the Utility had current regulatory liabilities of $965 million and $1.2 billion respectively. At December 31, 2025, current regulatory liabilities consisted primarily of billed revenues exceeding FERC TO formula rate 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)	2025		2024
Cost of removal obligations (1)	$	9,488	$	8,943
Public purpose programs (2)	1,169		1,112
Employee benefit plans (3)	1,043		1,088
Transmission tower wireless licenses (4)	257		306
SFGO sale (5)	—		79
SB 901 securitization (6)	6,010		6,295
Wildfire self-insurance (7)	1,035		804
Other (8)	1,186		790
Total noncurrent regulatory liabilities	$	20,188	$	19,417

(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.

(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. See Note 5 below.

(7) Represents amounts collected through rates designated for wildfire self-insurance, plus earnings on investments and less operating expenses of wildfire self-insurance. Balance at December 31, 2025 includes amounts collected through both CPUC and FERC rates. Balance at December 31, 2024 includes only amounts collected through CPUC rates. See Note 14 below.

(8) Includes amounts collected through FERC rates designated for wildfire self-insurance at December 31, 2024. 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 $419 million, $537 million, and $547 million for the years ended December 31, 2025, 2024, and 2023, respectively. Interest expense from balancing accounts payable was $223 million, $323 million, and $257 million for the years ended December 31, 2025, 2024, and 2023, respectively.

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

	Receivable<br>Balance at December 31,
(in millions)	2025		2024
Electric distribution (1)	$	1,465	$	1,591
Electric transmission (2)	122		117
Gas distribution and transmission (3)	142		387
Energy procurement (4)	2,711		1,066
Public purpose programs (5)	151		162
Wildfire-related accounts (6)	84		979
Insurance premium costs (7)	—		38
Residential uncollectibles balancing accounts (8)	278		260
Catastrophic event memorandum account (9)	181		500
General rate case memorandum accounts (10)	—		1,113
Other	1,166		1,014
Total regulatory balancing accounts receivable	$	6,300	$	7,227
	Payable<br>Balance at December 31,
---	---	---	---	---
(in millions)	2025		2024
Electric transmission (2)	$	37	$	883
Gas distribution and transmission (3)	78		72
Energy procurement (4)	1,502		329
Public purpose programs (5)	472		882
SFGO sale	83		93
Wildfire-related accounts (6)	338		337
Nuclear decommissioning adjustment mechanism (11)	1		23
Other	608		550
Total regulatory balancing accounts payable	$	3,119	$	3,169

(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 limits on electric and gas service disconnections for residential customers.

(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, 2022 WMCE final decision, and 2023 WMCE final decision.

(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.

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, 2025:

(in millions)	Termination<br>Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility<br>Availability
Utility revolving credit facility	June 2030	$	5,400	(1)	$	(1,575)	$	(639)	$	3,186
Utility Receivables Securitization Program (2)	June 2027	1,750		(3)	(1,750)		—		—		(3)
PG&E Corporation revolving credit facility	June 2028	650			—		—		650
Total credit facilities		$	7,800		$	(3,325)	$	(639)	$	3,836

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

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

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity date to April 10, 2026. 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 23, 2025, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 21, 2030, (ii) increase the aggregate commitments from $4.4 billion to $5.4 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2025, the Utility and the SPV amended the existing $1.5 billion Receivables Securitization Program to, among other things, (i) extend the scheduled termination date from June 26, 2026 to June 25, 2027 and (ii) allow the Utility and the SPV to request an increase to the commitments by an additional aggregate amount of up to $250 million, subject to the satisfaction of certain terms and conditions.

On September 24, 2025, the Utility entered into a Term Loan Credit Agreement, pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $500 million (the “Term Loan”). The Term Loan bears interest based on the Utility’s election of either (1) Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%. The Utility borrowed the entire amount of the Term Loan on September 24, 2025. The Term Loan has a maturity date of September 23, 2026.

On December 19, 2025, the Utility amended its existing $525 million term loan agreement to, among other things, (i) increase the borrowing capacity to $600 million, (ii) extend the maturity date to December 18, 2026 and (iii) revise the interest rate based on the Utility’s election of either (1) the Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%.

PG&E Corporation

On June 23, 2025, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2028, (ii) increase the aggregate commitments from $500 million to $650 million and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

Long-Term Debt Issuances and Redemptions

Utility

On February 24, 2025, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of 5.700% First Mortgage Bonds due 2035 and (ii) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for (i) the repayment of all of its $600 million aggregate principal amount of 3.500% First Mortgage Bonds due June 15, 2025, and (ii) the repayment of all of its $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 4, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, and (ii) $850 million aggregate principal amount of 6.000% First Mortgage Bonds due 2035. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026.

On October 2, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, (ii) $850 million aggregate principal amount of 5.050% First Mortgage Bonds due 2032, and (iii) $750 million aggregate principal amount of 6.100% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026. The Utility used the remaining net proceeds from the offerings 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, 2025, 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, 2025 and 2024, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion and $2.13 billion, with unamortized debt issuance costs of $13 million and $20 million, respectively, in Long-term debt. For the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $91 million, $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, 2025		December 31, 2024
PG&E Corporation
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		1,500
Unamortized discount, premium and debt issuance costs, net		(29)		(39)
Total PG&E Corporation Long-Term Debt		5,621		5,611
Utility
First Mortgage Bonds - Stated Maturity:
2025	3.45% - 4.95%	—		1,925
2026	2.95%	600		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 5.00%	2,775		1,975
2029	4.20% - 6.10%	2,100		2,100
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,900		1,050
2033	6.15% - 6.40%	1,900		1,900
2034	5.80% - 6.95%	1,900		1,900
2035	5.70% - 6.00%	1,850		—
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		2,300
2054	5.90%	750		750
2055	6.10% - 6.15%	1,500		—
Less: current portion, net of unamortized discount and debt issuance costs		(600)		(1,924)
Unamortized discount, premium and debt issuance costs, net		(247)		(226)
Total Utility First Mortgage Bonds		39,354		36,927
Recovery Bonds (1)		10,145		10,367
Less: current portion		(221)		(222)
DWR Loan (2)		738		886
Credit Facilities
Receivables Securitization Program - Stated Maturity: 2027	variable rate (3)	1,750		—
Total Utility Long-Term Debt		51,766		47,958
Total PG&E Corporation Consolidated Long-Term Debt		$	57,387	$	53,569

(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 the 2024 Form 10-K. 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.

(3) At December 31, 2025, the contractual SOFR-based interest rate on the Receivables Securitization Program was 5.31%.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2025 are reflected in the table below:

(in millions, except interest rates)	2026			2027			2028			2029			2030			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	4.25		%	5.00		%	—		%	5.25		%	7.38		%	5.39		%
Fixed rate obligations	$	—		$	2,150		$	1,000		$	—		$	1,000		$	1,500		$	5,650
Utility (1)
Average fixed interest rate	2.95		%	3.22		%	3.99		%	5.52		%	4.55		%	4.90		%	4.69		%
Fixed rate obligations	$	600		$	3,000		$	2,775		$	2,100		$	3,100		$	28,626		$	40,201
Variable interest rate as of December 31, 2025	—		%	5.31		%	—		%	—		%	—		%	—		%	5.31		%
Variable rate obligations	$	—		$	1,750		$	—		$	—		$	—		$	—		$	1,750
Recovery Bonds (2)
AB 1054 obligations	$	81		$	84		$	88		$	91		$	95		$	2,633		$	3,072
SB 901 obligations	140			146			152			159			165			6,311			7,073
Total consolidated debt	$	821		$	7,130		$	4,015		$	2,350		$	4,360		$	39,070		$	57,746

(1) The balance excludes the 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 the 2024 Form 10-K. 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, 2025.

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. As of December 31, 2025, the Utility had made all required upfront contributions. 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 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 years ended December 31, 2025 and 2024, the Utility recorded $302 million and $328 million, respectively, 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)	2025		2024
Balance at January 1	$	5,194	$	5,249
Amortization	(105)		(55)
Balance at December 31	$	5,089	$	5,194
	SB 901 securitization regulatory liability
---	---	---	---	---
(in millions)	2025		2024
Balance at January 1	$	(6,295)	$	(6,628)
Amortization	407		383
Additions(1)	(122)		(50)
Balance at December 31	$	(6,010)	$	(6,295)

(1) Includes $87 million and $16 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2025 and 2024, respectively.

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 2,197,942,874 shares of common stock outstanding at December 31, 2025, excluding 477,743,590 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2025.

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.

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, 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.

California law requires that a corporation must pass either a retained earnings test or an asset to liabilities ratio test to declare a dividend, ensuring it can 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.

The following table summarizes the dividends on common stock paid or declared by PG&E Corporation and the Utility in 2025:

Security		Amount per Share			Aggregate amount (in millions)			Date of Declaration		Record Date		Payment Date
PG&E Corporation common stock		$	0.025		$	55		November 29, 2024		December 31, 2024		January 15, 2025
	0.025			55			February 20, 2025		March 31, 2025		April 15, 2025
	0.025			55			May 22, 2025		June 30, 2025		July 15, 2025
	0.025			55			September 18, 2025		September 30, 2025		October 15, 2025
	0.05			110			December 11, 2025		December 31, 2025		January 15, 2026
Utility common stock		(1)			575			February 20, 2025		(1)		March 18, 2025
	(1)			575			May 22, 2025		(1)		May 30, 2025
	(1)			575			September 18, 2025		(1)		September 26, 2025
	(1)			625			December 11, 2025		(1)		December 18, 2025

(1) PG&E Corporation owns all of the outstanding shares of Utility common stock.

Long-Term Incentive Plans

The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 51,401,320 shares were available for future awards at December 31, 2025.

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

(in millions)	2025		2024		2023
Restricted stock units	80		67		64
Performance shares	54		31		27
Total compensation expense (pre-tax)	$	134	$	98	$	91
Total compensation expense (after-tax)	$	97	$	71	$	65

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 grant date.  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, 2025, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the grant date is estimated using the Black-Scholes valuation method. No stock options were granted in 2025 or 2024.

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the grant date.  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 grant date.  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, 2025.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2025:

	Number of<br>Stock Options	Weighted Average Grant-<br>Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1	743,963	$	10.23
Granted (1)	—	—
Exercised	—	—
Forfeited or expired	(111,495)	10.23
Outstanding at December 31	632,468	10.23		1.91
Vested or expected to vest at December 31	632,468	10.23		1.91
Exercisable at December 31	632,468	$	10.23	1.91

(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 2025, 2024, and 2023 was $16.43, $16.74, and $15.70, respectively.  The total fair value of restricted stock units that vested during 2025, 2024, and 2023 was $70 million, $62 million, and $64 million, respectively.  The tax benefit from restricted stock units that vested in 2025 was $8 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, 2025, $108 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.60 years.

The following table summarizes restricted stock unit activity for 2025:

	Number of<br>Restricted Stock Units	Weighted Average Grant-<br>Date Fair Value
Nonvested at January 1	9,423,582	$	15.52
Granted	6,252,871	16.43
Vested	(4,744,176)	14.66
Forfeited	(254,623)	16.21
Nonvested at December 31	10,677,654	$	16.42

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 2025, 2024, and 2023 was $15.10, $16.94, and $13.39 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, 2025, $39 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.14 years.

The following table summarizes activity for performance shares in 2025:

	Number of<br>Performance Shares	Weighted Average Grant-<br>Date Fair Value
Nonvested at January 1	7,180,206	$	15.52
Granted	2,445,690	15.10
Vested	(2,831,269)	11.21
Forfeited	(332,132)	16.39
Nonvested at December 31	6,462,495	$	16.40

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.

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, 2025 and 2024, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

Dividends

PG&E Corporation

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.

Dividends on the Mandatory Convertible Preferred Stock are cumulative. 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.

Utility

At December 31, 2025, 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, 2025, 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 following table summarizes the dividends on preferred stock paid or declared by PG&E Corporation and the Utility in 2025:

Security		Amount per Share			Aggregate amount (in millions)			Date of Declaration		Record Date		Payment Date
PG&E Corporation mandatory convertible preferred stock		$	0.7167		$	23		December 12, 2024		February 14, 2025		February 27, 2025
	0.75			24			February 20, 2025		May 15, 2025		May 29, 2025
	0.75			24			May 22, 2025		August 15, 2025		August 28, 2025
	0.75			24			September 18, 2025		November 14, 2025		December 1, 2025
		0.75			24			December 11, 2025		February 13, 2026		March 1, 2026
Utility preferred stock		varies by series			3.5			November 29, 2024		January 31, 2025		February 15, 2025
	varies by series			3.5			February 20, 2025		April 30, 2025		May 15, 2025
	varies by series			3.5			May 22, 2025		July 31, 2025		August 15, 2025
	varies by series			3.5			September 18, 2025		October 31, 2025		November 15, 2025
		varies by series			3.5			December 11, 2025		January 30, 2026		February 15, 2026

For more information on dividend policy, see Note 6 above.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2025, 2024, and 2023.

	Year Ended December 31,
(in millions, except per share amounts)	2025		2024		2023
Income available for common shareholders	$	2,593	$	2,475	$	2,242
Weighted average common shares outstanding, basic (1)	2,197		2,141		2,064
Add incremental shares from assumed conversions:
Employee share-based compensation	5		6		6
Equity Units	—		—		68
Weighted average common shares outstanding, diluted	2,202		2,147		2,138
Total earnings per common share, diluted	$	1.18	$	1.15	$	1.05

(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, 2025, 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.

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 or tax carryforwards.

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.

In general, 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 expense (benefit) were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2025		2024		2023		2025		2024		2023
Current:
Federal	$	(1)	$	2	$	(1)	$	(1)	$	2	$	(1)
State	50		(78)		—		89		(78)		—
Deferred:
Federal	(225)		(137)		(1,047)		(171)		(72)		(981)
State	(102)		15		(507)		(109)		45		(477)
Federal tax credits	(2)		(2)		(2)		(2)		(2)		(2)
Total income tax benefit	$	(280)	$	(200)	$	(1,557)	$	(194)	$	(105)	$	(1,461)

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

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2025		2024		2025		2024
Deferred income tax assets:
Tax carryforwards	$	9,752	$	9,429	$	9,199	$	8,955
Compensation	211		171		127		86
GHG allowances	457		471		457		471
Wildfire-related claims (1)	227		295		227		295
Operating lease liability	111		78		111		78
Transmission tower wireless license	251		251		251		251
Bad debt	137		127		137		127
Other (2)	127		140		156		137
Total deferred income tax assets	$	11,273	$	10,962	$	10,665	$	10,400
Deferred income tax liabilities:
Property-related basis difference	12,357		11,021		12,344		11,009
Regulatory balancing accounts	487		878		487		878
Income tax regulatory asset (3)	1,723		1,335		1,723		1,335
Debt financing costs	353		390		353		390
Operating lease ROU asset	111		78		111		78
Environmental reserve	288		248		288		248
Other (4)	89		94		91		94
Total deferred income tax liabilities	$	15,408	$	14,044	$	15,397	$	14,032
Total net deferred income tax liabilities	$	4,135	$	3,082	$	4,732	$	3,632

(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.

(4) Amounts primarily include property taxes.

The following tables reconcile income tax expense at the federal statutory rate to the income tax provision:

	PG&E Corporation
	Year Ended December 31,
(in millions)	2025				2024				2023
Federal statutory income tax rate	21.0	%	$	486	21.0	%	$	478	21.0	%	$	144
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(1.8)		(41)		(2.0)		(45)		(57.9)		(397)
Effect of regulatory treatment of fixed asset differences (2)	(34.2)		(790)		(28.9)		(657)		(62.4)		(428)
Changes in valuation allowance	0.8		18		(0.9)		(20)		0.7		5
Nontaxable or nondeductible items	2.2		51		0.8		19		0.2		1
Tax credits	(1.1)		(26)		(1.0)		(22)		(3.4)		(24)
Changes in unrecognized tax benefits	0.1		3		2.1		46		0.2		2
Fire Victim Trust (3)	—		—		—		—		(126.9)		(869)
Other, net	0.9		19		0.1		1		1.3		9
Effective tax rate	(12.1)	%	$	(280)	(8.8)	%	$	(200)	(227.2)	%	$	(1,557)

(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.

(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.

	Utility
	Year Ended December 31,
(in millions)	2025				2024				2023
Federal statutory income tax rate	21.0	%	$	606	21.0	%	$	547	21.0	%	$	228
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(0.6)		(16)		(0.8)		(22)		(34.4)		(373)
Effect of regulatory treatment of fixed asset differences (2)	(27.4)		(790)		(25.2)		(657)		(39.5)		(428)
Changes in valuation allowance	—		—		—		—		0.1		1
Nontaxable or nondeductible items	1.1		30		0.4		12		—		—
Tax credits	(0.9)		(26)		(0.9)		(22)		(2.2)		(24)
Changes in unrecognized tax benefits	0.1		3		1.9		49		0.2		2
Fire Victim Trust (3)	—		—		—		—		(80.2)		(869)
Other, net	—		(1)		(0.4)		(12)		0.2		2
Effective tax rate	(6.7)	%	$	(194)	(4.0)	%	$	(105)	(134.8)	%	$	(1,461)

(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.

(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2025		2024		2023		2025		2024		2023
Balance at beginning of year	$	454	$	616	$	570	$	454	$	616	$	570
Additions for tax position taken during a prior year	5		—		1		5		—		1
Reductions for tax position taken during a prior year	(7)		(257)		—		(7)		(257)		—
Additions for tax position taken during the current year	665		95		45		665		95		45
Balance at end of year	$	1,117	$	454	$	616	$	1,117	$	454	$	616

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2025 for PG&E Corporation and the Utility was $102 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, 2025, 2024, and 2023, 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. PG&E Corporation decreased its Income tax benefit by $70 million related to state and federal income taxes in 2024. 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, 2025		Expiration<br>Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,307	2031 - 2036
Net operating loss carryforward - Post-2017	34,957		N/A
Tax credit carryforward	226		Various
State:
Net operating loss carryforward	$	34,143	2039 - 2041
Tax credit carryforward	167		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.

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, 2025	December 31, 2024
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	232,825,834	179,257,247
	Options	48,215,000	37,717,500
Electricity (MWh)	Forwards, futures, and swaps	7,196,942	8,576,078
	Options	1,650,800	1,663,200
	Congestion Revenue Rights (3)	93,712,644	123,040,895

(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, 2025, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative<br>Balance		Netting		Total Derivative<br>Balance
Current assets – other	$	165	$	(46)	$	119
Noncurrent assets – other	170		(6)		164
Current liabilities – other	(169)		46		(123)
Noncurrent liabilities – other	(106)		6		(100)
Total commodity risk	$	60	$	—	$	60

As of December 31, 2024, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative<br>Balance		Netting		Total Derivative<br>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

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, 2025, 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, self-insurance assets, 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, 2025
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	634	$	—	$	—	$	—	$	634
Fixed-income securities	—		—		—		—		—
Self-insurance investments
Short-term investments	1,120		—		—		—		1,120
Total Self-insurance investments (2)	1,120		—		—		—		1,120
Nuclear decommissioning trusts
Short-term investments	94		—		—		—		94
Global equity securities	2,433		—		—		—		2,433
Fixed-income securities	1,445		1,113		—		—		2,558
Assets measured at NAV	—		—		—		—		26
Total nuclear decommissioning trusts (3)	3,972		1,113		—		—		5,111
Customer credit trust
Short-term investments	111		—		—		—		111
Global equity securities	—		—		—		—		—
Fixed-income securities	367		326		—		—		693
Total customer credit trust	478		326		—		—		804
Price risk management instruments (Note 10)
Electricity	—		19		283		(6)		296
Gas	—		33		—		(46)		(13)
Total price risk management instruments	—		52		283		(52)		283
Rabbi trusts
Short-term investments	115		—		—		—		115
Global equity securities	5		—		—		—		5
Life insurance contracts	—		65		—		—		65
Total rabbi trusts	120		65		—		—		185
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		127
Total long-term disability trust	10		—		—		—		137
TOTAL ASSETS	$	6,334	$	1,556	$	283	$	(52)	$	8,274
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	80	$	130	$	(6)	$	204
Gas	—		65		—		(46)		19
TOTAL LIABILITIES	$	—	$	145	$	130	$	(52)	$	223

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

(2) Includes $1 billion and $77 million held in the entities for wildfire and non-wildfire self-insurance, respectively.

(3) Represents amount before deducting $881 million primarily related to deferred taxes on appreciation of investment value.

	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.

(2) Represents amount before deducting $747 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, 2025 or 2024.

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.

Self-insurance investments

Investments held in Pacific Energy Risk Solutions, LLC and Pacific Casualty Insurance Company, 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 <br>(in millions)
	At December 31, 2025				Valuation<br>Technique	Unobservable<br>Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	252	$	83	Market approach	CRR auction prices		$ (74) - 74 / 2
Power purchase agreements	$	31	$	47	Discounted cash flow	Forward prices		$ 11 - 106 / 53

(1) Represents price per MWh.

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

	Fair Value <br>(in millions)
	At December 31, 2024				Valuation<br>Technique	Unobservable<br>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.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2025 and 2024:

	Price Risk Management Instruments
(in millions)	2025		2024
Asset balance as of January 1	$	127	$	191
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	26		(64)
Asset balance as of December 31	$	153	$	127

(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, and customer deposits approximate their carrying values as of December 31, 2025 and December 31, 2024, 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, 2025				At December 31, 2024
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	5,360	$	5,697	$	5,358	$	5,829
Utility	38,145		35,565		37,812		34,532

(1) As of December 31, 2025, 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<br>Cost		Total<br>Unrealized<br>Gains		Total<br>Unrealized<br>Losses		Total Fair<br>Value
As of December 31, 2025
Nuclear decommissioning trusts
Short-term investments	$	94	$	—	$	—	$	94
Global equity securities	324		2,140		(5)		2,459
Fixed-income securities	2,557		48		(47)		2,558
Total (1)	$	2,975	$	2,188	$	(52)	$	5,111
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

(1) Represents amounts before deducting $881 million and $747 million as of December 31, 2025 and December 31, 2024, 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, 2025
Less than 1 year	$	95
1–5 years	822
5–10 years	564
More than 10 years	1,077
Total maturities of fixed-income securities	$	2,558

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

(in millions)	2025		2024		2023
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	1,952	$	1,980	$	2,235
Gross realized gains on securities	213		255		80
Gross realized losses on securities	(25)		(63)		(74)

Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)	Amortized<br>Cost		Total<br>Unrealized<br>Gains		Total<br>Unrealized<br>Losses		Total Fair<br>Value
As of December 31, 2025
Customer credit trust
Short-term investments	$	111	$	—	$	—	$	111
Global equity securities	—		—		—		—
Fixed-income securities	689		5		(1)		693
Total	$	800	$	5	$	(1)	$	804
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

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

	As of
(in millions)	December 31, 2025
Less than 1 year	$	290
1–5 years	107
5–10 years	49
More than 10 years	247
Total maturities of fixed-income securities	$	693

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

(in millions)	2025		2024		2023
Proceeds from sales and maturities of customer credit trust investments	$	435	$	398	$	556
Gross realized gains on securities	131		10		$	23
Gross realized losses on securities	(20)		(8)		$	(19)

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.

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 2025 and 2024:

Pension Plan

(in millions)	2025		2024
Change in plan assets:
Fair value of plan assets at beginning of year	$	16,767	$	17,211
Actual return on plan assets	1,779		218
Company contributions	337		337
Benefits and expenses paid	(1,020)		(999)
Fair value of plan assets at end of year	$	17,863	$	16,767
Change in benefit obligation:
Benefit obligation at beginning of year	$	17,585	$	17,697
Service cost for benefits earned	424		396
Interest cost	1,007		916
Actuarial loss (gain) (1)	427		(424)
Benefits and expenses paid	(1,020)		(1,000)
Benefit obligation at end of year (2)	$	18,423	$	17,585
Funded Status:
Current liability	$	(10)	$	(10)
Noncurrent liability	(550)		(808)
Net liability at end of year	$	(560)	$	(818)

(1) The actuarial loss for the year ended December 31, 2025 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in demographic assumptions; 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.

(2) PG&E Corporation’s accumulated benefit obligation was $16.5 billion and $15.8 billion at December 31, 2025 and 2024, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2025		2024
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,471	$	2,499
Actual return on plan assets	200		74
Company contributions	7		5
Plan participant contribution	91		84
Benefits and expenses paid	(196)		(191)
Fair value of plan assets at end of year	$	2,573	$	2,471
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,279	$	1,377
Service cost for benefits earned	38		41
Interest cost	73		71
Actuarial loss (gain) (1)	125		(123)
Benefits and expenses paid	(182)		(174)
Federal subsidy on benefits paid	4		3
Plan participant contributions	91		84
Benefit obligation at end of year	$	1,428	$	1,279
Funded Status: (2)
Noncurrent asset	$	1,144	$	1,192
Noncurrent liability	—		—
Net asset at end of year	$	1,144	$	1,192

(1) The actuarial loss for the year ended December 31, 2025 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations and unfavorable changes in claims cost, medical trends, and demographic assumptions. 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.

(2) At December 31, 2025 and 2024, 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 $274 million and $322 million as of December 31, 2025, and $261 million and $296 million as of December 31, 2024, 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)	2025		2024		2023
Service cost for benefits earned (1)	$	424	$	396	$	379
Interest cost	1,007		916		913
Expected return on plan assets	(1,053)		(1,014)		(981)
Amortization of prior service cost	(3)		(3)		(4)
Amortization of net actuarial loss	2		1		1
Net periodic benefit cost	377		296		308
Less: transfer to regulatory account (2)	(40)		39		25
Total expense recognized	$	337	$	335	$	333

(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.

(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)	2025		2024		2023
Service cost for benefits earned (1)	$	38	$	41	$	38
Interest cost	73		71		73
Expected return on plan assets	(150)		(139)		(132)
Amortization of prior service cost	3		3		3
Amortization of net actuarial gain	(23)		(23)		(19)
Net periodic benefit cost	$	(59)	$	(47)	$	(37)

(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.

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,
	2025		2024		2023		2025	2024	2023
Discount rate	5.58	%	5.76	%	5.21	%	5.51 - 5.60%	5.71 - 5.76%	5.18 - 5.22%
Rate of future compensation increases	4.80	%	4.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	7.00	%	6.40	%	6.00	%	4.30 - 7.20%	3.90 - 7.20%	3.70 - 7.00%
Interest crediting rate for cash balance plan	4.23	%	4.41	%	3.86	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2025 was 7.00%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2036 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 7.0% compares to a ten-year actual return of 5.7%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 831 Aa-grade non-callable bonds at December 31, 2025.  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 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
	2026		2025		2024		2026		2025		2024
Global equity securities	28	%	26	%	26	%	14	%	30	%	29	%
Absolute return	1		1		1		—		—		—
Real assets	6		8		8		3		3		3
Fixed-income securities	65		65		65		83		67		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, 2025 and 2024.

	Fair Value Measurements
	At December 31,
	2025								2024
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	452	$	30	$	—	$	482	$	126	$	47	$	—	$	173
Global equity securities	1,445		—		—		1,445		1,310		—		—		1,310
Real assets	2		—		—		2		437		—		—		437
Fixed-income securities	1,990		6,880		12		8,882		2,180		6,367		16		8,563
Assets measured at NAV	—		—		—		7,052		—		—		—		6,284
Total	$	3,889	$	6,910	$	12	$	17,863	$	4,053	$	6,414	$	16	$	16,767
PBOP Plans:
Short-term investments	$	546	$	—	$	—	$	546	$	27	$	—	$	—	$	27
Global equity securities	2		—		—		2		60		—		—		60
Real assets	—		—		—		—		20		—		—		20
Fixed-income securities	518		561		—		1,079		431		751		1		1,183
Assets measured at NAV	—		—		—		946		—		—		—		1,181
Total	$	1,066	$	561	$	—	$	2,573	$	538	$	751	$	1	$	2,471
Total plan assets at fair value							$	20,436							$	19,238

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 private real estate funds. These funds are measured at NAV as a practical expedient.

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, 2025 or 2024.

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, 2025 and 2024:

(in millions)
For the year ended December 31, 2025	Fixed-Income
Balance at beginning of year	$	16
Actual return on plan assets:
Relating to assets still held at the reporting date	7
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	(10)
Balance at end of year	$	12
(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

There were no material transfers out of Level 3 in 2025 or 2024.

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 $7 million to the other postretirement benefit plans in 2025.  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 qualified pension plan in 2026. PG&E Corporation and the Utility plan to contribute $31 million to the long-term disability trusts in 2026, as authorized in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2025, 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<br>Plan	PBOP<br>Plans	Federal<br>Subsidy
2026	993	84	(1)
2027	1,082	86	(1)
2028	1,110	90	(1)
2029	1,136	93	(1)
2030	1,161	96	(1)
2031-2035	6,159	523	(6)

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 $194 million, $175 million, and $158 million in 2025, 2024, and 2023, 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) plus five percent of direct labor costs or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are priced at the lower of fully loaded cost or fair market value. 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.

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 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.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual 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 estimated liabilities 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.

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 and equipment 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. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. 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.

The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. Claims related to the 2019 Kincade fire are 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, 2025.

Payments (in millions)
2019 Kincade Fire	$	1,287
2021 Dixie Fire	1,908
2022 Mosquito Fire	107
Total at December 31, 2025	$	3,302

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 4, 2026, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 3,014 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.

On October 11, 2022, the Utility entered into a tolling agreement with 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 $1.225 billion as of December 31, 2024 (before available insurance). In each of the first and second quarters of 2025, PG&E Corporation and the Utility recorded additional charges of $50 million, for an aggregate liability of $1.325 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include any claims related to Cal OES or any punitive damages.

The following table presents changes in the best estimate 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, 2024.

Loss Accrual (in millions)
Balance at December 31, 2024	$	267
Accrued Losses	100
Payments	(329)
Balance at December 31, 2025	$	38

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

As of December 31, 2025, the Utility received $111 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below.

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 Recoveries under AB 1054 and SB 254” 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 4, 2026, PG&E Corporation and the Utility are aware of approximately 189 complaints on behalf of at least 9,034 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A trial with respect to one plaintiff has been scheduled for December 2, 2026. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025. No bellwether trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates.

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 and motion to strike 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 April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On April 30, 2025, in response to the Court of Appeal’s request, Cal Fire filed an opposition to the Utility’s writ. The Utility filed a reply to the opposition on May 9, 2025. As of February 4, 2026, the writ remains pending with the Court of Appeal.

On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, and the hearing date on the motion is scheduled for June 18, 2026.

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 $1.925 billion as of December 31, 2024 (before available recoveries). 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 2025 of $225 million, of which $25 million was recorded in the fourth quarter, for an aggregate liability of $2.150 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.150 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 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, 2024.

Loss Accrual (in millions)
Balance at December 31, 2024	$	567
Accrued Losses	225
Payments	(549)
Balance at December 31, 2025	$	243

As of December 31, 2025, the Utility recorded an insurance receivable of $521 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $1.150 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025. 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 Recoveries under AB 1054 and SB 254” below. As of December 31, 2025, the Utility also recorded a $97 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 $535 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 4, 2026, PG&E Corporation and the Utility are aware of approximately 35 complaints on behalf of at least 2,939 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and a group of six public entities have each filed complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into settlement agreements with five public entities. The court has set individual claimant bellwether trial dates for April 13, 2026.

On May 28, 2025, the Utility executed an amendment to a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

On August 21, 2025, Cal Fire filed a complaint against the Utility for fire suppression and investigation costs.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million as of December 31, 2024 (before available recoveries). During 2025, PG&E Corporation and the Utility recorded additional charges of $250 million, of which $100 million was recorded in the fourth quarter, for an aggregate liability of $350 million (before available recoveries).

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) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA 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 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 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, 2024.

Loss Accrual (in millions)
Balance at December 31, 2024	$	82
Accrued Losses	250
Payments	(89)
Balance at December 31, 2025	$	243

As of December 31, 2025, the Utility recorded an insurance receivable of $363 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of December 31, 2025, 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 $54 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, 2025 are:

Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	521	$	363
FERC TO rates	97		7
WEMA	535		54
Wildfire Fund	1,150		—
Probable recoveries at December 31, 2025 (1)	$	2,303	$	424

(1) Includes legal costs of $148 million and $73 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2025.

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, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $521 million and $363 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, 2024:

Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2024	$	27	$	90	$	117
Accrued insurance recoveries	(6)		273		267
Reimbursements	(20)		(82)		(102)
Balance at December 31, 2025	$	1	$	281	$	282

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 electrical corporation’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, 2025, the Utility recorded reductions of $97 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 Recoveries under AB 1054 and SB 254” below. As of December 31, 2025, 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 $535 million and $54 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 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. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. 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, 2025 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account 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. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $4.7 billion for 2025. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2025 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 or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

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.

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 utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. 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 utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

AB 1054 authorizes the payment of funds to a participating utility where that utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

PG&E Corporation and the Utility’s Wildfire Fund recoveries are reflected in Wildfire-related claims, net of recoveries in the Consolidated Statements of Income to the extent PG&E Corporation and the Utility determine that it is probable the CPUC will conclude that the Utility’s conduct was just and reasonable or when the Utility is not otherwise required to reimburse the Wildfire Fund.

As of December 31, 2025, PG&E Corporation and the Utility recorded $295 million and $4 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 claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2024:

Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2024	$	756
Accrued Wildfire Fund recoveries	225
Claims paid by Wildfire Fund	(682)
Balance at December 31, 2025	$	299

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.

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. 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 the Public Employee Retirement Association of New Mexico (“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 certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. A hearing on the motion for preliminary approval in the District Court is scheduled for February 26, 2026. Putative class members would have the right to opt out of the proposed settlement.

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.

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.

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 Matters

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.  Estimated liabilities for contingencies related to such matters totaled $151 million and $74 million as of December 31, 2025 and 2024, 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 above. 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

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. 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 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. Where 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. 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, 2025		December 31, 2024
Topock natural gas compressor station	$	315	$	294
Hinkley natural gas compressor station	99		97
Former MGP sites owned by the Utility or third parties (1)	715		782
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	71		76
Fossil fuel-fired generation facilities and sites (3)	17		18
Total environmental remediation liability	$	1,217	$	1,267

(1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street.

(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’s environmental remediation liability as of December 31, 2025, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. 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.  As of December 31, 2025, the Utility expected to recover $1.0 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available.

	Balance at December 31, 2025
(in millions)	Low end of the range		High end of the range		HSMA Recovery (1)
Topock natural gas compressor station (2)	$	315	$	518	Available
Hinkley natural gas compressor station (2)	99		221		Unavailable
Former MGP sites owned by the Utility or third parties (3)	715		1,292		Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)	71		146		Available
Fossil fuel-fired generation facilities and sites (5)	17		32		Unavailable

(1) For sites where HSMA recovery is available, the Utility expects to recover 90% of the costs associated with environmental remediation through rates.

(2) The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years.

(3) 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.

(4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation.

(5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site.

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 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. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. 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 $43 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, 2025:

	Power Purchase Agreements
(in millions)	Renewable<br>Energy		Conventional<br>Energy		Natural<br>Gas		Other (1)		Total
2026	$	1,937	$	1,058	$	544	$	278	$	3,817
2027	1,921		1,035		193		134		3,283
2028	1,903		989		106		47		3,045
2029	1,858		905		98		6		2,867
2030	1,852		510		42		2		2,406
Thereafter	12,828		4,315		34		5		17,182
Total purchase commitments	$	22,299	$	8,812	$	1,017	$	472	$	32,600

(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 2026 and 2047.

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 2026 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, 2025, QF contracts in operation expire at various dates between 2026 and 2049.  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 $2.0 billion in 2025, $2.1 billion in 2024, and $2.4 billion in 2023.

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 2026 and 2035.  In addition, the Utility has contracted for natural gas storage services in Northern California and Canada 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 $1.0 billion in 2025, $0.8 billion in 2024, and $2.5 billion in 2023.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2026 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 $134 million in 2025, $294 million in 2024, and $180 million in 2023.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities leases and land leases which expire at various dates between 2026 and 2054, as well as other multi-year agreements.  At December 31, 2025, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2026	$	82
2027	51
2028	41
2029	39
2030	13
Thereafter	65
Total minimum payments	$	291

Payments for other commitments were $63 million in 2025, $105 million in 2024, and $106 million in 2023.  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, if the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution to the customer credit trust 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.

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 (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).  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, 2025, 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, 2025.

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, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 11, 2026, 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 Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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.

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.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 11, 2026

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

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 11, 2026, 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 Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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.

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.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 11, 2026

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

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, 2025, 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, 2025, 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, 2025, of the Company and our report dated February 11, 2026, 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 11, 2026

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, 2025, 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, 2025, 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, 2025, of the Utility and our report dated February 11, 2026, 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 11, 2026

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 defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2025, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective as of such date 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 2025 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, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this 2025 Form 10-K.

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, 2025 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 3, 2025, John R. Simon, who serves as the Executive Vice President, General Counsel and Chief Ethics and Compliance Officer of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) under the Exchange Act, for the sale of up to 50,000 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of August 1, 2026 or the execution of the sale of all 50,000 shares.

On November 4, 2025, Patricia K. Poppe, who serves as the Chief Executive Officer of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c), for the sale of up to 62,500 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of July 31, 2026 or the execution of the sale of all 62,500 shares.

On November 13, 2025, Sumeet Singh, who serves as the Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery of the Utility, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions 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 Mr. Singh receives when his performance share units (“PSUs”) vest. Assuming that the PSUs vest at 100% of target, this Rule 10b5-1 plan would entail the sale of 52,450 shares, but the actual number could vary based on the number of PSUs that vest. In addition, 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 May 15, 2026 or the execution of the sale of all covered shares.

On November 25, 2025, 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 conditions of Rule 10b5-1(c), for the sale of up to 10,000 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of December 31, 2026 or the execution of the sale of all 10,000 shares.

On December 11, 2025, Carla J. Peterman, who serves as the President, PG&E Corporation, and Executive Vice President, Customer & Corporate Affairs of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions 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 PSUs vest. Assuming that the PSUs vest at 100% of target, this Rule 10b5-1 plan would entail the sale of 96,095 shares, but the actual number could vary based on the number of PSUs that vest. In addition, 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 November 30, 2026 or the execution of the sale of all covered shares.

Certain officers have made elections to participate in, and are participating in, the PG&E Corporation Retirement Savings 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(c) 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.

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 2025 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 2026 Annual Meetings of Shareholders to be filed with the SEC within 120 days after the companies’ fiscal year end of December 31, 2025 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 “2026 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 either Code of Conduct that applies to the respective executive officers or directors of PG&E Corporation or the Utility will be posted on PG&E Corporation’s website, www.pgecorp.com.

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 - 2025,” “Grants of Plan-Based Awards in 2025,” “Outstanding Equity Awards at Fiscal Year End - 2025,” “Option Exercises and Stock Vested during 2025,” “Pension Benefits - 2025,” “Non-Qualified Deferred Compensation - 2025,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability,” “Compensation of Non-Employee Directors,” and “Principal Executive Officers’ (PEO) Pay Ratio - 2025,” in the Joint Proxy Statement relating to the 2026 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 will be 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 2026 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Equity Compensation Plan Information

The following table provides information as of December 31, 2025 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	22,859,547	(1)	$	41.27	(2)	51,401,320	(3)
Equity compensation plans not approved by shareholders	—		—			—
Total equity compensation plans	22,859,547	(1)	$	41.27	(2)	51,401,320	(3)

(1) Includes 162 phantom stock units, 10,842,071 restricted stock units and 11,384,846 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 632,468 options outstanding as of December 31, 2025.

(3) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, 2025. 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 2026 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 2026 Annual Meetings of Shareholders, which information is incorporated herein by reference.

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, 2025, 2024, and 2023 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024, and 2023 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2025 and 2024 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2025, 2024, and 2023 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2025, 2024, and 2023 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, 2025 and 2024 and for the Years Ended December 31, 2025, 2024, and 2023.

Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2025, 2024, and 2023.

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)
3.5	Bylaws of Pacific Gas and Electric Company, Amended and Restated as of December 11, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 11, 2025 (File No. 1-2348), Exhibit 3.1)
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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), Exhibit3.1)
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)
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)
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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)
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)
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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)
4.5.26	Twenty-Seventh Supplemental Indenture, dated as of February 20, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2025 (File No. 1-2348), Exhibit 4.4)
4.5.27	Twenty-Eighth Supplemental Indenture, dated as of February 26, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 24, 2025 (File No. 1-2348), Exhibit 4.1)
4.5.28	Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 2, 2025 (File No. 1-2348), Exhibit 4.1)
4.5.29	Thirtieth Supplemental Indenture, dated as of September 24, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 24, 2025 (File No. 1-2348), Exhibit 4.1)
4.5.30	Thirty-First Supplemental Indenture, dated as of October 2, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 30, 2025 (File No. 1-12609), Exhibit 4.1)
4.5.31	Thirty-Second Supplemental Indenture, dated as of November 14, 2025
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)
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10.2	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)
10.2.1	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)
10.2.2	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)
10.2.3	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)
10.2.4	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)
10.2.5	Amendment No. 5 to Credit Agreement, dated as of June 23, 2025, 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 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 23, 2025 (File No. 1-2348), Exhibit 10.2)
10.3	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)
10.4	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)
10.4.1	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)
10.4.2	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)
10.4.3	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)
10.4.4	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)
10.4.5	Amendment No. 5 to Credit Agreement, dated as of June 23, 2025, 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 23, 2025 (File No. 1-2348), Exhibit 10.1)
10.5	Term Loan Credit Agreement, dated as of September 24, 2025, among Pacific Gas and Electric Company, the several lenders from time to time parties thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 24, 2025 (File No. 1-2348), Exhibit 10.1)
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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)
10.6.4	Amendment No. 4 to Credit Agreement, dated as of April 11, 2025, 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, 2025 (File No. 1-12348), Exhibit 10.2)
10.6.5	Amendment No. 5 to Credit Agreement, dated as of December 19, 2025, among Pacific Gas and Electric Company, the lenders party thereto, and Bank of America, N.A., as administrative agent
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)
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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)
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)
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10.8.13		Amendment No. 13 to Receivables Financing Agreement, dated as of June 26, 2025, 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, 2025 (File No. 1-2348), Exhibit 10.4)
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		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)
10.12	*	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)
10.13	*	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)
10.14	*	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)
10.15	*	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)
10.16	*	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)
10.17	*	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)
10.18	*	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)
10.19	*	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)
10.20	*	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)
10.21	*	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)
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10.22	*	Pacific Gas and Electric Company Officer Relocation Guide, effective as of May 1, 2022
10.23	*	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)
10.23.1	*	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)
10.23.2	*	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)
10.23.3	*	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)
10.23.4	*	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)
10.24	*	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)
10.25	*	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)
10.26	*	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)
10.27	*	PG&E Corporation 2021 Long-Term Incentive Plan, as amended effective as of May 22, 2025 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2025 (File No. 1-12609), Exhibit 10.5)
10.28	*	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)
10.29	*	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)
10.30	*	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)
10.31	*	Form of Restricted Stock Unit Agreement for 2025 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, 2025 (File No. 1-12609), Exhibit 10.6)
10.32	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Restricted Stock Unit Award, as amended effective as of August 14, 2022
10.33	*	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)
10.34	*	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)
10.35	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Program-Specific Retention Stock Unit Award Agreement, effective February 19, 2025 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2025 (File No. 1-12609), Exhibit 10.4)
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10.36	*	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)
10.37	*	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)
10.38	*	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)
10.39	*	PG&E Corporation 2010 Executive Stock Ownership Guidelines, as amended effective as of December 10, 2025
10.40	*	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)
10.41	*	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)
10.42	*	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)
10.43	*	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)
10.44	*	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)
10.45	*	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)
10.46	*	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)
10.47	*	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)
10.48	*	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)
10.49	*	Form of Director and Officer Indemnification Agreement, as amended effective as of February 20, 2025 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2025 (File No. 1-12609), Exhibit 10.3)
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
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31.2		Certifications of the Principal Executive Officer 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 Officer 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.

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, 2025 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:	Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery
Date:	February 11, 2026	Date:	February 11, 2026		Signature	Title	Date
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A.  Principal Executive Officers
/s/ PATRICIA K. POPPE	Chief Executive Officer	February 11, 2026
Patricia K. Poppe	(PG&E Corporation)			/s/ SUMEET SINGH	Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery	February 11, 2026
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Sumeet Singh	(Pacific Gas and Electric Company)
B. Principal Financial Officers
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/s/ CAROLYN J. BURKE	Executive Vice President and Chief Financial Officer	February 11, 2026
Carolyn J. Burke	(PG&E Corporation)			/s/ STEPHANIE N. WILLIAMS	Vice President and Controller (PG&E Corporation)	February 11, 2026
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Stephanie N. Williams	Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company)
C. Principal Accounting Officer
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/s/ STEPHANIE N. WILLIAMS	Vice President and Controller (PG&E Corporation)	February 11, 2026
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)
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*	/s/ RAJAT BAHRI	Director	February 11, 2026
	Rajat Bahri				*	/s/ CHERYL F. CAMPBELL	Director	February 11, 2026
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	Cheryl F. Campbell	Chair of the Board (Pacific Gas and Electric Company)			*	/s/ EDWARD G. CANNIZZARO	Director	February 11, 2026
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	Edward G. Cannizzaro				*	/s/ KERRY W. COOPER	Director	February 11, 2026
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	Kerry W. Cooper	Chair of the Board (PG&E Corporation)
*	/s/ LEO P. DENAULT	Director	February 11, 2026
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	Leo P. Denault				*	/s/ JESSICA L. DENECOUR	Director	February 11, 2026
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	Jessica L. Denecour				*	/s/ MARK E. FERGUSON III	Director	February 11, 2026
---	---	---	---
	Mark E. Ferguson III
*	/s/ W. CRAIG FUGATE	Director	February 11, 2026
---	---	---	---
	W. Craig Fugate
*	/s/ ARNO L. HARRIS	Director	February 11, 2026
---	---	---	---
	Arno L. Harris
*	/s/ CARLOS M. HERNANDEZ	Director	February 11, 2026
---	---	---	---
	Carlos M. Hernandez
*	/s/ JOHN O. LARSEN	Director	February 11, 2026
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	John O. Larsen				*	/s/ PATRICIA K. POPPE	Director	February 11, 2026
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	Patricia K. Poppe				*	/s/ WILLIAM L. SMITH	Director	February 11, 2026
---	---	---	---
	William L. Smith
*	/s/ BENJAMIN F. WILSON	Director	February 11, 2026
---	---	---	---
	Benjamin F. Wilson
*	/s/ SUMEET SINGH	Director (Pacific Gas and Electric Company)	February 11, 2026
---	---	---	---
	Sumeet Singh
*By:	/s/ JOHN R. SIMON	February 11, 2026
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	John R. Simon, Attorney-in-Fact

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)	2025		2024		2023
Administrative service revenue	$	194	$	146	$	154
Operating expenses	(207)		(167)		(165)
Interest income	11		15		13
Interest expense	(315)		(270)		(365)
Other expense	(145)		(17)		(21)
Equity in earnings of subsidiaries	3,065		2,697		2,530
Income Before Income Taxes	2,603		2,404		2,146
Income tax benefit	(86)		(94)		(96)
Net Income	$	2,689	$	2,498	$	2,242
Preferred stock dividend requirement	96		23		—
Income Available for Common Shareholders	$	2,593	$	2,475	$	2,242
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $0, $3, and $6, at respective dates)	(3)		(7)		(16)
Net unrealized gain on available-for-sale securities (net of taxes of $0, $0, and $0, respectively)	—		1		—
Total other comprehensive income (loss)	(3)		(6)		(16)
Comprehensive Income	$	2,590	$	2,469	$	2,226
Weighted Average Common Shares Outstanding, Basic	2,197		2,141		2,064
Weighted Average Common Shares Outstanding, Diluted	2,202		2,147		2,138
Net Earnings Per Common Share, Basic	$	1.18	$	1.16	$	1.09
Net Earnings Per Common Share, Diluted	$	1.18	$	1.15	$	1.05

PG&E CORPORATION

SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)

CONSOLIDATED BALANCE SHEETS

	Balance at December 31,
(in millions)	2025		2024
ASSETS
Current Assets
Cash and cash equivalents	$	360	$	235
Restricted cash and restricted cash equivalents	1		1
Advances to affiliates	54		13
Income taxes receivable	39		2
Total current assets	454		251
Other Noncurrent Assets
Investments in subsidiaries	45,110		42,829
Other investments	182		175
Deferred income taxes	682		633
Total other noncurrent assets	45,974		43,637
TOTAL ASSETS	$	46,428	$	43,888
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable – other	146		36
Income taxes payable	—		1
Other current liabilities	444		420
Total current liabilities	590		457
Noncurrent Liabilities
Long-term debt	5,622		5,612
Other noncurrent liabilities	151		141
Total noncurrent liabilities	5,773		5,753
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		1,579
Common stock	39,168		39,086
Reinvested earnings	(650)		(2,966)
Accumulated other comprehensive loss	(32)		(21)
Total shareholders’ equity	40,065		37,678
TOTAL LIABILITIES AND EQUITY	$	46,428	$	43,888

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,
	2025		2024		2023
Cash Flows from Operating Activities:
Net income	$	2,689	$	2,498	$	2,242
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	82		53		4
Equity in earnings of subsidiaries	(3,065)		(2,699)		(2,530)
Deferred income taxes and tax credits, net	(49)		(94)		(116)
Current income taxes payable	(33)		—		9
Other	55		9		40
Net cash used in operating activities	(321)		(233)		(351)
Cash Flows From Investing Activities:
Investment in subsidiaries	(1,575)		(5,360)		(1,290)
Dividends received from subsidiaries (1)	2,350		2,025		1,775
Net cash provided by (used in) investing activities	775		(3,335)		485
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, $0, and $27 at respective dates	—		—		2,123
Proceeds from issuance of long-term debt, net of premium and<br><br>issuance costs of $0, $4, and $0 at respective dates	—		1,496		—
Common stock issued	—		1,128		—
Mandatory convertible preferred stock issued	—		1,579		—
Mandatory convertible preferred stock dividends paid	(97)		—		—
Common stock dividend paid	(220)		(86)		—
Other	(12)		(8)		(6)
Net cash provided by (used in) financing activities	(329)		3,609		(64)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	125		41		70
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	236		195		125
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31	$	361	$	236	$	195
Less: Restricted cash and restricted cash equivalents	(1)		(1)		(3)
Cash and cash equivalents at December 31	$	360	$	235	$	192
Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(306)	$	(215)	$	(309)
Supplemental disclosures of noncash investing and financing activities
Changes to PG&E Corporation common stock and treasury stock in connection <br>    with the share exchange with the Fire Victim Trust	$	—	$	—	$	(2,517)
Common stock dividends declared but not yet paid	111		55		21
Mandatory convertible preferred stock dividends declared but not yet paid	23		23		—

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

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2025, 2024, and 2023

(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:
2025:
Allowance for uncollectible accounts (1)	$	418	$	362	$	—	$	372	$	408
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445

(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, 2025, 2024, and 2023

(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:
2025:
Allowance for uncollectible accounts (1)	$	418	$	362	$	—	$	372	$	408
2024:
Allowance for uncollectible accounts (1)	$	445	$	312	$	—	$	339	$	418
2023:
Allowance for uncollectible accounts (1)	$	166	$	624	$	—	$	345	$	445

(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.

178

Document

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, 2025, there were approximately 2,675,686,464 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 series will 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.

Document

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 11, 2025 (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, 2025, 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.

Document

EXHIBIT 4.5.31

Execution Version

TO BE RECORDED AND WHEN

RECORDED RETURN TO:

Hunton Andrews Kurth LLP

550 South Hope Street, Suite 2000

Los Angeles, CA 90071

Attention: Christopher W. Hasbrouck, Esq.

THIRTY-SECOND SUPPLEMENTAL INDENTURE

DATED AS OF NOVEMBER 14, 2025

SUPPLEMENT TO INDENTURE OF MORTGAGE DATED AS OF JUNE 19, 2020

PACIFIC GAS AND ELECTRIC COMPANY Issuer (Mortgagor)

and

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., Trustee (Mortgagee)

TABLE OF CONTENTS

ARTICLE II ESTABLISHMENT OF THE BOND OF THE SIXTY-NINTH SERIES3

ARTICLE III AMENDMENT, SUPPLEMENT AND WAIVER4

ARTICLE IV COVENANTS5

ARTICLE V MISCELLANEOUS5

EXHIBIT A – FORM OF THE BOND OF THE SIXTY-NINTH SERIES

SCHEDULE 1 – MORTGAGE INDENTURE RECORDING INFORMATION

i

THIRTY-SECOND SUPPLEMENTAL INDENTURE, dated as of November 14, 2025 (this “Thirty-Second Supplemental Indenture”), by and between PACIFIC GAS AND ELECTRIC COMPANY, a California corporation, as Issuer (Mortgagor) (the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., a national banking association organized under the laws of the United States of America, as Trustee and Mortgagee under the Mortgage Indenture (as hereinafter defined) (the “Trustee”).

RECITALS OF THE COMPANY

A.    The Company and the Trustee are parties to that certain Indenture of Mortgage, dated as of June 19, 2020 (together with all indentures supplemental thereto, the “Mortgage Indenture”), providing for the issuance by the Company of Bonds (as defined in the Mortgage Indenture) from time to time.

B.    Under the Mortgage Indenture, the Company is authorized to issue unlimited series of Bonds and establish one or more series of Bonds at any time in accordance with the provisions of the Mortgage Indenture, and the terms of such series of Bonds may be described by a supplemental indenture executed by the Company and the Trustee.

C.    Pursuant to the Letter of Credit Agreement (as hereinafter defined) and Section 3.01 of the Mortgage Indenture, the Company and the Trustee deem it advisable to enter into this Thirty-Second Supplemental Indenture for the purposes of establishing the terms of the Bond of the Sixty-Ninth Series (as hereinafter defined).

D.    The execution and delivery of this Thirty-Second Supplemental Indenture has been authorized by a Board Resolution (as defined in the Mortgage Indenture).

E.    Concurrent with the execution hereof, the Company has delivered to the Trustee an Officer’s Certificate (as defined in the Mortgage Indenture) and has caused its counsel to deliver to the Trustee an Opinion of Counsel (as defined in the Mortgage Indenture) pursuant to Section 14.03 of the Mortgage Indenture.

F.    The Company has done all things necessary to make this Thirty-Second Supplemental Indenture a valid agreement of the Company in accordance with its terms.

NOW, THEREFORE, the Company and the Trustee agree, for the benefit of each other and the equal and proportionate benefit of all Holders of the Bond of the series established hereby, as follows:

ARTICLE I

DEFINITIONS

Unless the context otherwise requires, capitalized terms used but not defined herein have the meaning set forth in the Mortgage Indenture.

The words “herein,” “hereof” and “hereunder” and other words of similar import refer to this Thirty-Second Supplemental Indenture as a whole and not to any particular Article, Section or other subdivision.

The following additional definitions are hereby established for purposes of this Thirty-Second Supplemental Indenture and shall have the meanings set forth in this Thirty-Second Supplemental Indenture only for purposes of this Thirty-Second Supplemental Indenture.

“Administrative Agent” has the meaning ascribed to it in the Letter of Credit Agreement.

“Ascertainable Fees” means any fees due and payable under the Loan Documents and any other written fee agreements from time to time entered into in connection with the Letter of Credit Agreement by the Company and any other party to the Letter of Credit Agreement (the “Related Fee Letters”), including facility fees, administrative agent fees, fronting fees, arranger fees and up-front fees, that are determinable with reasonable certainty by the Company solely by reference to the Loan Documents or the Related Fee Letters.

“Collateral Bond” means the Bond of the Sixty-Ninth Series.

“Electronic Means” means the following communications methods: e-mail, secure electronic transmission containing applicable authorization codes, passwords and/or authentication keys issued by the Trustee, or another method or system specified by the Trustee as available for use in connection with its services hereunder.

“Interest Amount” means, without duplication, interest on all Obligations, and all Ascertainable Fees and interest thereon (including, for the avoidance of doubt, any default interest), due and payable under the Loan Documents and Related Fee Letters.

“Interest Payment Date” means each date on which Interest Amounts are due and payable pursuant to the Loan Documents.

“Letter of Credit Agreement” means the Letter of Credit Agreement, dated as of November 14, 2025, by and among the Company and Crédit Agricole Corporate and Investment Bank, as Issuer and Administrative Agent, as amended, supplemented, restated or otherwise modified from time to time.

“Letters of Credit” has the meaning ascribed to it in the Letter of Credit Agreement.

“Loan Documents” has the meaning ascribed to it in the Letter of Credit Agreement.

“Obligations” means all Obligations (as defined in the Letter of Credit Agreement) including Reimbursement Obligations, but excluding Ascertainable Fees and the Interest Amount.

“Reimbursement Obligations” has the meaning ascribed to it in the Letter of Credit Agreement.

ARTICLE II

ESTABLISHMENT OF THE BOND OF THE SIXTY-NINTH SERIES

Section 201    Establishment of the Bond of the Sixty-Ninth Series.

Pursuant to the terms hereof and Section 3.01 and Article V of the Mortgage Indenture, the Company hereby establishes a Sixty-Ninth series of Bonds designated as the “Bond of the Sixty-Ninth Series” (the “Bond of the Sixty-Ninth Series”). The Bond of the Sixty-Ninth Series shall be fully registered in the name of and delivered to Crédit Agricole Corporate and Investment Bank, as Administrative Agent under the Letter of Credit Agreement.

Section 202    Form of the Bond of the Sixty-Ninth Series.

The Bond of the Sixty-Ninth Series shall be issued in certificated form and the form of the Bond of the Sixty-Ninth Series is set forth in Exhibit A hereto and is hereby incorporated herein and made a part hereof.

Section 203    Principal Amount of the Bond of the Sixty-Ninth Series.

The Bond of the Sixty-Ninth Series shall be dated November 14, 2025 and be issued in an initial face amount of $100,000,000, which face amount shall represent the maximum principal amount of the Bond of the Sixty-Ninth Series and such amount shall be subject to increases or decreases in the aggregate principal amount of the Bond of the Sixty-Ninth Series as evidenced by Schedule A attached thereto, without amendment hereof, pursuant to the Loan Documents and the procedures identified in Section 502 of this Thirty-Second Supplemental Indenture. The amount of principal payable on the Bond of the Sixty-Ninth Series, and the date or dates on which such principal is payable, shall be as set forth in said Bond. For all purposes of the Mortgage Indenture, the principal amount of the Bond of the Sixty-Ninth Series Outstanding as of any date of calculation shall be equal to the Obligations (as defined in the Bond of the Sixty-Ninth Series) outstanding under the Loan Documents (as defined in the Bond of the Sixty-Ninth Series) as of such date, but in no event shall the principal amount of such Bond as of any date of calculation be greater than the then current face amount of such Bond. The initial face amount of the Bond of the Sixty-Ninth Series may be increased or reduced from time to time as set forth in said Bond and the procedures identified in Section 502 of this Thirty-Second Supplemental Indenture. Principal of the Bond of the Sixty-Ninth Series shall be payable without the presentment or surrender thereof.

Section 204    Interest Rates; Interest Payment Dates; Stated Maturity of the Bond of the Sixty-Ninth Series.

The Bond of the Sixty-Ninth Series shall bear interest at the rate or rates, and interest with respect thereto will be payable on the Interest Payment Dates, in each case for such Obligations, set forth in said Bond. The Bond of the Sixty-Ninth Series shall have a Stated

Maturity of November 14, 2030 (as the same may be extended, without amendment hereof, pursuant to the Loan Documents (as defined in the Letter of Credit Agreement) and the procedures identified in Section 501 of this Thirty-Second Supplemental Indenture). Interest on the Bond of the Sixty-Ninth Series shall accrue from the same dates that interest, if any, accrues on outstanding Obligations pursuant to the Loan Documents until such interest is paid.

Section 205    No Redemption; No Sinking Fund.

The Bond of the Sixty-Ninth Series shall not be subject to redemption prior to its Stated Maturity. No sinking fund is provided for the Bond of the Sixty-Ninth Series.

Section 206    Paying Agent and Bond Registrar.

The Trustee is hereby appointed as initial Paying Agent and initial Bond Registrar for the Bond of the Sixty-Ninth Series. The Place of Payment of the Bond of the Sixty-Ninth Series shall be the Corporate Trust Office of the Trustee; provided, however, that the Company reserves the right to change, by one or more Officer’s Certificates any such place or the Bond Registrar; provided, further, that the Company reserves the right to designate, by one or more Officer’s Certificates, one or more of its offices as any such place or itself as the Bond Registrar.

Section 207    No Exchanges; Limitations on Transfers.

The Bond of the Sixty-Ninth Series may not be exchanged for any other Bond, except as provided in Section 3.06 of the Mortgage Indenture, and may not be transferred except to effect an assignment thereof to a successor or an assign of the Administrative Agent. The Company may take such actions as it shall deem necessary, desirable or appropriate to effect compliance with such restrictions on transfer, including the issuance of stop-transfer instructions to the Trustee or any other transfer agent.

Section 208    Other Terms of the Bond of the Sixty-Ninth Series.

The other terms of the Bond of the Sixty-Ninth Series shall be as expressly set forth herein and in Exhibit A hereto.

ARTICLE III

AMENDMENT, SUPPLEMENT AND WAIVER

The Trustee and the Company may not modify, amend or supplement this Thirty-Second Supplemental Indenture except as set forth in Article XIV of the Mortgage Indenture as if (a) references in Article XIV to “this Indenture” and “hereto” are deemed to include the Thirty-Second Supplemental Indenture, and (b) references to the Bonds of any series “Outstanding under this Indenture” (or similar expressions and phrases) are deemed to refer only to the Collateral Bond established hereby and no other Bonds.

ARTICLE IV

COVENANTS

Each of the agreements and covenants of the Company contained in Article VII of the Mortgage Indenture shall apply to the Collateral Bond established hereby as of the Original Issue Date (as defined in the Collateral Bond).

ARTICLE V

MISCELLANEOUS

Section 501    Extension Procedures for the Collateral Bond.

From time to time, the Maturity Date specified on the Collateral Bond may be extended, without amendment hereof, pursuant to the Loan Documents when the Company delivers to the Trustee each of the following:

(a)    An Officer’s Certificate stating that (i) to the knowledge of the signer, no Event of Default has occurred and is continuing and (ii) the Maturity Date corresponding to the Collateral Bond has been extended pursuant to the terms of the Loan Documents and specifying such new Maturity Date. Such Officer’s Certificate shall provide as an exhibit a copy of a notice executed by the Administrative Agent confirming that the Maturity Date corresponding to the Collateral Bond has been extended pursuant to the terms of the Loan Documents and specifying such new Maturity Date.

(b)    A Company Order requesting the Trustee update the Maturity Date corresponding to the Collateral Bond to such new Maturity Date and authenticate a replacement Collateral Bond upon surrender by the Administrative Agent of the existing certificated Collateral Bond and to cancel and dispose of, in the manner provided in the Mortgage Indenture, such existing certificated Bond, and upon such cancellation and disposition, such existing certificated Bond shall no longer be considered Outstanding.

Section 502    Amendment Procedures for Principal Amount of the Collateral Bond.

From time to time, the principal amount specified on the Collateral Bond may be increased or decreased as evidenced by Schedule A attached thereto, without amendment hereof, pursuant to the Loan Documents when the Company delivers to the Trustee each of the following:

(a)    An Officer’s Certificate stating that (i) to the knowledge of the signer, no Event of Default has occurred and is continuing, (ii) the principal amount corresponding to the Collateral Bond has been increased or decreased pursuant to the terms of the Loan Documents and specifying such new principal amount and (iii) in the case of an increase in the principal amount of the Collateral Bond, the conditions thereto as set forth in the Mortgage Indenture are satisfied. Such Officer’s Certificate shall provide as an exhibit a copy of a notice executed by the

Administrative Agent confirming that the principal amount corresponding to the Collateral Bond has been amended pursuant to the terms of the Loan Documents and specifying such new principal amount.

(b)    A Company Order requesting the Trustee update the principal amount corresponding to the Collateral Bond to such new principal amount and either (i) upon receipt of the existing certificated Collateral Bond from the Administrative Agent, update Schedule A attached thereto and return such updated Collateral Bond to the Administrative Agent or (ii) authenticate a replacement Collateral Bond upon surrender by the Administrative Agent of the existing certificated Collateral Bond and to cancel and dispose of, in the manner provided in the Mortgage Indenture, such existing certificated Bond, and upon such cancellation and disposition, such existing certificated Bond shall no longer be considered Outstanding.

Section 503    Procedures for the Authentication of Replacement Bonds Representing the Bond of the Sixty-Ninth Series.

From time to time, the terms of the Loan Documents may require that the Bond of the Sixty-Ninth Series be represented by multiple certificated Bonds that, in the aggregate, represent the Bond of the Sixty-Ninth Series (collectively, the “Replacement Bonds of the Sixty-Ninth Series”) to account for amendments to the Letter of Credit Agreement that result in a portion of the Letters of Credit (as defined in the Letter of Credit Agreement) having a different Maturity Date or other terms. The Bond of the Sixty-Ninth Series may be amended and replaced by any number of Replacement Bonds of the Sixty-Ninth Series, without amendment hereof, pursuant to the Loan Documents when the Company delivers to the Trustee each of the following:

(a)    An Officer’s Certificate stating that (i) to the knowledge of the signer, no Event of Default has occurred and is continuing and (ii) a description of the amendment that was made to the Letter of Credit Agreement giving rise to the need to issue such Replacement Bonds of the Sixty-Ninth Series. Such Officer’s Certificate shall provide as an exhibit a copy of a notice executed by the Administrative Agent confirming such changes and new terms for the Replacement Bonds of the Sixty-Ninth Series.

(b)    A Company Order requesting the Trustee authenticate the Replacement Bonds of the Sixty-Ninth Series with the Maturity Date(s) and principal amount(s) specified in the Officer’s Certificate delivered pursuant to Section 503(a) of this Thirty-Second Supplemental Indenture upon surrender by the Administrative Agent of the existing certificated Bond of the Sixty-Ninth Series and to cancel and dispose of, in the manner provided in the Mortgage Indenture, such existing certificated Bond, and upon such cancellation and disposition, such existing certificated Bond shall no longer be considered Outstanding.

(c)    For purposes of this Thirty-Second Supplemental Indenture, the term “Bond of the Sixty-Ninth Series” shall become “Bonds of the Sixty-Ninth Series” upon satisfaction of the requirements of Section 503(a) and (b) of this Thirty-Second Supplemental Indenture and the Trustee’s authentication of any Replacement Bonds of the Sixty-Ninth Series.

Section 504    Concerning the Trustee.

The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Thirty-Second Supplemental Indenture or the due execution hereof by the Company, or for or in respect of the recitals and statements contained herein, all of which recitals and statements are made solely by the Company. Except as herein otherwise provided, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Thirty-Second Supplemental Indenture other than as set forth in the Mortgage Indenture; and this Thirty-Second Supplemental Indenture is executed and accepted on behalf of the Trustee, subject to all the terms and conditions set forth in the Mortgage Indenture, as fully to all intents as if the same were herein set forth at length.

Section 505    Application of Thirty-Second Supplemental Indenture.

Except as provided herein, each and every term and condition contained in this Thirty-Second Supplemental Indenture that modifies, amends or supplements the terms and conditions of the Mortgage Indenture shall apply only to the Bonds of the series established hereby and not to any other series of Bonds established under the Mortgage Indenture. Except as specifically amended and supplemented by, or to the extent inconsistent with, this Thirty-Second Supplemental Indenture, the Mortgage Indenture shall remain in full force and effect and is hereby ratified and confirmed.

Section 506    Headings.

The headings of the several Articles of this Thirty-Second Supplemental Indenture are inserted for convenience of reference, and shall not be deemed to be any part hereof.

Section 507    Effective Date.

This Thirty-Second Supplemental Indenture shall be effective upon the execution and delivery hereof by each of the parties hereto.

Section 508    Counterparts.

This Thirty-Second Supplemental Indenture may be executed in any number of counterparts, and each of such counterparts shall together constitute but one and the same instrument. Delivery of an executed Thirty-Second Supplemental Indenture by one party to the other may be made by electronic mail (including any electronic signature complying with the New York Electronic Signatures and Records Act (N.Y. State Tech. §§ 301-309), as amended from time to time, or other applicable law) or other transmission method, and the parties hereto agree that any counterpart so delivered shall be deemed to have been duly and validly delivered and be valid and effective for all purposes.

Section 509    Governing Law.

The laws of the State of New York shall govern this Thirty-Second Supplemental Indenture and the Collateral Bond, without giving effect to applicable principles of conflicts of

law to the extent that the application of the laws of another jurisdiction would be required thereby.

Section 510    Severability.

In case any provision in this Thirty-Second Supplemental Indenture and the Collateral Bond shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

Section 511    Incorporation by Reference.

The terms of Schedule 1 attached hereto are incorporated herein and made a part hereof by this reference.

Section 512    Electronic Communication.

With respect to the Collateral Bond under this Thirty-Second Supplemental Indenture, the Trustee shall have the right to accept and act upon instructions (“Instructions”), given pursuant to this Thirty-Second Supplemental Indenture and delivered using Electronic Means; provided, however, that the Company shall provide to the Trustee an incumbency certificate listing Authorized Officers and containing specimen signatures of such Authorized Officers, which incumbency certificate shall be amended by the Company whenever a person is to be added or deleted from the listing. If the Company elects to give the Trustee Instructions using Electronic Means and the Trustee in its discretion elects to act upon such Instructions, the Trustee’s understanding of such Instructions shall be deemed controlling. The Company understands and agrees that the Trustee cannot determine the identity of the actual sender of such Instructions and that the Trustee shall conclusively presume that directions that purport to have been sent by an Authorized Officer listed on the incumbency certificate provided to the Trustee have been sent by such Authorized Officer. The Company shall be responsible for ensuring that only Authorized Officers transmit such Instructions to the Trustee and that the Company and all Authorized Officers are solely responsible to safeguard the use and confidentiality of applicable user and authorization codes, passwords and/or authentication keys upon receipt thereof by the Company. The Trustee shall not be liable for any losses, costs or expenses arising directly or indirectly from the Trustee’s reliance upon and compliance with such Instructions notwithstanding such directions conflict or are inconsistent with a subsequent written instruction. The Company agrees: (i) to assume all risks arising out of the use of Electronic Means to submit Instructions to the Trustee including without limitation the risk of the Trustee acting on unauthorized Instructions, and the risk of interception and misuse by third parties; (ii) that it is fully informed of the protections and risks associated with the various methods of transmitting Instructions to the Trustee and that there may be more secure methods of transmitting Instructions than the method(s) selected by the Company; (iii) that the security procedures (if any) to be followed in connection with its transmission of Instructions provide to it a commercially reasonable degree of protection in light of its particular needs and circumstances; and (iv) to notify the Trustee immediately upon learning of any compromise or unauthorized use of the security procedures.

IN WITNESS WHEREOF, the parties hereto have caused this Thirty-Second Supplemental Indenture to be duly executed as of the day and year first above written.

PACIFIC GAS AND ELECTRIC COMPANY,

as Issuer (Mortgagor)

By:    /s/ Monica Klemann

Name:    Monica Klemann

Title:    Senior Director, Assistant Treasurer

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,

as Trustee (Mortgagee)

By:    /s/ Mary Jo Wagener

Name:    Mary Jo Wagener

Title:    Vice President

A notary public or other officer completing this certificate verifies only the identity of the<br><br>individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.

STATE OF CALIFORNIA         }

}

COUNTY OF ALAMEDA        }

On October 29, 2025, before me, A. Mosqueda-Striplin, Notary Public, personally appeared Monica Klemann, who proved to me on the basis of satisfactory evidence to be the person whose name is subscribed to the within instrument and acknowledged to me that she executed the same in her authorized capacity, and that by her signature on the instrument the person, or the entity upon behalf of which the person acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature /s/ A. Mosqueda-Striplin___

Signature of Notary Public

(Seal)

A notary public or other officer completing this certificate verifies only the identity of the<br><br>individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.

STATE OF TEXAS             }

}

COUNTY OF    HARRIS        }

On November 4, 2025, before me, April Michelle Bradley, personally appeared Mary Jo Wagener, Vice President, who proved to me on the basis of satisfactory evidence to be the person whose name is subscribed to the within instrument and acknowledged to me that she executed the same in her authorized capacity, and that by her signature on the instrument the person, or the entity upon behalf of which the person acted, executed the instrument.

WITNESS my hand and official seal.

/s/ April Michelle Bradley_______

Signature

(Seal)

EXHIBIT A

[FORM OF BOND OF THE SIXTY-NINTH SERIES]

[FORM OF FACE OF BOND]

NOTE: THE HOLDER OF THIS BOND BY ACCEPTANCE HEREOF AGREES TO RESTRICTIONS ON TRANSFER, TO WAIVERS OF CERTAIN RIGHTS OF EXCHANGE, AND TO INDEMNIFICATION PROVISIONS AS SET FORTH BELOW. IN ADDITION, THE BOND REPRESENTED BY THIS CERTIFICATE HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 AND SUCH BOND OR ANY INTEREST THEREIN MAY NOT BE TRANSFERRED WITHOUT COMPLIANCE WITH APPLICABLE SECURITIES LAWS.

THIS BOND IS NOT TRANSFERABLE EXCEPT TO A SUCCESSOR OR ASSIGN OF THE ADMINISTRATIVE AGENT UNDER THE LETTER OF CREDIT AGREEMENT REFERRED TO HEREIN AMONG THE COMPANY (AS DEFINED HEREIN) AND THE SEVERAL PARTIES THERETO. THE COMPANY MAY TAKE SUCH ACTIONS AS IT SHALL DEEM NECESSARY, DESIRABLE, OR APPROPRIATE TO EFFECT COMPLIANCE WITH THESE RESTRICTIONS ON TRANSFER, INCLUDING THE ISSUANCE OF STOP -TRANSFER INSTRUCTIONS TO THE TRUSTEE (AS DEFINED HEREIN) UNDER THE MORTGAGE INDENTURE REFERRED TO HEREIN OR ANY OTHER TRANSFER AGENT THEREUNDER.

AS SET FORTH HEREIN, THE OUTSTANDING PRINCIPAL AMOUNT OF THIS BOND AT ANY TIME MAY BE LESS THAN THE AMOUNT SHOWN ON THE FACE HEREOF.

THE FOLLOWING SUMMARY OF TERMS IS SUBJECT TO THE INFORMATION SET FORTH IN THIS BOND:

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ORIGINAL ISSUE DATE: November [__], 2025	FACE AMOUNT: $__________(as the same may be amended, without amendment hereof, pursuant to the Loan Documents and the procedures identified in Section 502 of the Thirty-Second Supplemental Indenture)	INTEREST RATE: See below
MATURITY DATE: November [__], 2030 (as the same may be extended, without amendment hereof, pursuant to the Loan Documents and the procedures identified in Section 501 of the Thirty-Second Supplemental Indenture)	INTEREST PAYMENT DATES: See below	THIS BOND IS A:<br> Global Book-Entry Bond<br> Certificated Bond
REGISTERED OWNER: Crédit Agricole Corporate and Investment Bank, as Administrative Agent under the Letter of Credit Agreement (as defined below), or any successor Administrative Agent under the Letter of Credit Agreement

This Bond is not a Discount Bond

within the meaning of the within mentioned Mortgage Indenture

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PACIFIC GAS AND ELECTRIC COMPANY

Bond of the Sixty-Ninth Series

Face Amount (as the same may be amended, without amendment hereof, pursuant to the Loan Documents and the procedures identified in Section 502 of the Thirty-Second Supplemental Indenture): $_______

No. _______

PACIFIC GAS AND ELECTRIC COMPANY, a corporation duly organized and existing under the laws of the State of California (herein called the “Company,” which term includes any successor Person pursuant to the applicable provisions of the Mortgage Indenture hereinafter referred to), for value received, hereby promises to pay to CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as Administrative Agent (the “Administrative Agent”), or its registered assigns, on behalf of the Secured Parties (as defined herein), the principal sum of up to _______ DOLLARS ($_______ ) or such lesser principal amount as shall be equal to the Obligations (as defined herein) due and payable under the Loan Documents (as defined herein) and as evidenced on Schedule A hereto pursuant to the procedures identified in Section 502 of the Thirty-Second Supplemental Indenture, and to pay interest with respect to this Bond at the Interest Rate (as defined herein) for such Obligations until the principal hereof is paid or duly made available for payment, but in each case not later than the Maturity Date specified above (as the same may be extended, without amendment hereof, pursuant to the Loan Documents and the procedures identified in Section 501 of the Thirty-Second Supplemental Indenture) or, in the event of default of the payment of the principal hereof, until the Company’s obligations with respect to the payment of such principal shall be discharged as provided in the Mortgage Indenture.

The principal amount outstanding under this Bond will increase or decrease from time to time to be equal at all times to the Obligations outstanding from time to time under the Loan Documents. The principal due and payable hereunder by the Company as of any date shall be equal to the Obligations due and payable under the Loan Documents on such date, and such principal shall be payable on the same dates (whether on the stated due dates or by acceleration pursuant to the terms of the Letter of Credit Agreement) as Obligations are payable from time to time pursuant to the Loan Documents. The obligation of the Company to make any payment of principal on this Bond shall be fully or partially, as the case may be, deemed to have been paid or otherwise satisfied and discharged to the extent that the Company has paid the Obligations due and payable under the Loan Documents, but any such payment shall not reduce the face amount (maximum principal amount) of this Bond unless the Uncommitted Facility Amount (as defined in the Letter of Credit Agreement) is irrevocably reduced in accordance with the Letter of Credit Agreement. If the Uncommitted Facility Amount is irrevocably reduced, the face amount (maximum principal amount) of this Bond shall be reduced by the same amount as the amount by which the Uncommitted Facility Amount is so reduced; provided, that for the avoidance of doubt, the face amount (maximum principal amount) of this Bond shall not be less than the

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aggregate principal amount of the Obligations under the Letter of Credit Agreement at the time of, and after giving effect to, such reduction and any concurrent repayment of Obligations.

Interest on this Bond shall be payable on each Interest Payment Date (as defined herein). The obligation of the Company to make any payment of interest with respect to this Bond shall be fully or partially, as the case may be, deemed to have been paid or otherwise satisfied and discharged to the extent that the Company has paid Interest Amounts (as defined herein) on the Obligations due and payable pursuant to the Loan Documents.

For purposes of this Bond:

“Administrative Agent” has the meaning ascribed to it in the Letter of Credit Agreement.

“Ascertainable Fees” means any fees due and payable under the Loan Documents and any other written fee agreements from time to time entered into in connection with the Letter of Credit Agreement by the Company and any other party to the Letter of Credit Agreement (the “Related Fee Letters”), including facility fees, administrative agent fees, fronting fees, arranger fees and up-front fees, that are determinable with reasonable certainty by the Company solely by reference to the Loan Documents or the Related Fee Letters.

“Interest Amount” means, without duplication, interest on all Obligations, and all Ascertainable Fees and interest thereon (including, for the avoidance of doubt, any default interest), due and payable under the Loan Documents and Related Fee Letters.

“Interest Payment Date” means each date on which Interest Amounts are due and payable pursuant to the Loan Documents.

“Interest Rate” means the applicable interest rate determined in accordance with Section 2.11 of the Letter of Credit Agreement.

“Letter of Credit Agreement” means the Letter of Credit Agreement, dated as of November 14, 2025, by and among the Company and Crédit Agricole Corporate and Investment Bank, as Issuer and Administrative Agent, as amended, supplemented, restated or otherwise modified from time to time.

“Letters of Credit” has the meaning ascribed to it in the Letter of Credit Agreement.

“Loan Documents” has the meaning ascribed to it in the Letter of Credit Agreement.

“Obligations” means all Obligations (as defined in the Letter of Credit Agreement) including Reimbursement Obligations, but excluding Ascertainable Fees and the Interest Amount.

“Reimbursement Obligations” has the meaning ascribed to it in the Letter of Credit Agreement.

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“Secured Parties” means, collectively, the Administrative Agent, the Issuer issuing Letters of Credit, each sub-agent appointed by the Administrative Agent from time to time pursuant to Section 9.2 of the Letter of Credit Agreement and any other Persons the Obligations owing to whom are or are purported to be secured by the Bond of the Sixty-Ninth Series.

Other capitalized terms used herein and not otherwise defined herein shall have the meanings specified in the Mortgage Indenture, unless otherwise noted or the context otherwise requires.

The Trustee (as defined herein) may conclusively presume that the obligation of the Company to pay the principal of and interest with respect to this Bond shall have been fully satisfied and discharged unless and until it shall have received a written notice from the Registered Owner (specified above), signed by an authorized officer of the Registered Owner, stating that the payment of principal of or interest with respect to this Bond has not been fully paid when due and specifying the amount of funds required to make such payment. The Trustee may also conclusively rely on any written notice from an authorized officer of the Registered Owner with respect to the principal amount Outstanding at any time on this Bond and the interest payable with respect to this Bond at any time and the date or dates on which such principal and interest are payable.

Payments of the principal of and interest with respect to this Bond shall be made at the Corporate Trust Office of the Trustee located initially in Los Angeles, California or at such other office or agency as may be designated for such purpose by the Company from time to time. Payment of the principal of and interest with respect to this Bond, as aforesaid, shall be made in such coin or currency of the United States of America as at the time of payment is legal tender for the payment of public and private debts.

The Maturity Date of this Bond specified above may be extended, without amendment hereof, pursuant to the terms of the Letter of Credit Agreement and the procedures identified in Section 501 of the Thirty-Second Supplemental Indenture.

The principal amount of this Bond specified above may be amended, without amendment hereof, pursuant to the terms of the Letter of Credit Agreement and such amended principal amount may be evidenced on Schedule A hereto pursuant to the procedures identified in Section 502 of the Thirty-Second Supplemental Indenture.

REFERENCE IS HEREBY MADE TO THE FURTHER PROVISIONS OF THIS BOND SET FORTH ON THE REVERSE HEREOF, WHICH FURTHER PROVISIONS SHALL FOR ALL PURPOSES HAVE THE SAME EFFECT AS IF SET FORTH AT THIS PLACE.

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Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual or electronic signature, this Bond shall not be entitled to any benefit under the Mortgage Indenture or be valid or obligatory for any purpose.

IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.

Dated: ________________

PACIFIC GAS AND ELECTRIC COMPANY

By __________________________________

By __________________________________

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TRUSTEE’S CERTIFICATE OF AUTHENTICATION

This is the Bond of the series designated as the Bonds of the Sixty-Ninth Series referred to in the within-mentioned Mortgage Indenture.

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Trustee

By

Authorized Signatory

Dated:

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[FORM OF REVERSE OF BOND OF THE SIXTY-NINTH SERIES]

This Bond of the Sixty-Ninth Series (this “Bond”) is one of a duly authorized issue of Bonds of the Company (the “Bonds”) issued and issuable in one or more series under and equally secured by an Indenture of Mortgage, dated as of June 19, 2020 (such Indenture as originally executed and delivered and as supplemented or amended from time to time thereafter, together with any constituent instruments establishing the terms of particular Bonds, being herein called the “Mortgage Indenture”), between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (herein called the “Trustee,” which term includes any successor trustee under the Mortgage Indenture), and reference is hereby made to the Mortgage Indenture for a description of the property mortgaged, pledged and held in trust, the nature and extent of the security and the respective rights, limitations of rights, duties and immunities of the Company, the Trustee and the Holders of the Bonds thereunder and of the terms and conditions upon which the Bonds are, and are to be, authenticated and delivered. The acceptance of this Bond shall be deemed to constitute the consent and agreement by the Holder hereof to all of the terms and provisions of the Mortgage Indenture.

This Bond is issued to the Administrative Agent by the Company pursuant to the Company’s obligations under the Loan Documents.

This Bond is not subject to redemption prior to the Maturity Date specified above.

As provided in the Mortgage Indenture and subject to certain limitations therein set forth, this Bond or any portion of the principal amount hereof will be deemed to have been paid for all purposes of the Mortgage Indenture and to be no longer Outstanding thereunder, and the Company’s entire indebtedness in respect thereof will be satisfied and discharged, if there has been irrevocably deposited with the Trustee or any Paying Agent (other than the Company), in trust, money in an amount which will be sufficient and/or Eligible Obligations, the principal of and interest on which when due, without regard to any reinvestment thereof, will provide moneys which, together with money, if any, deposited with or held by the Trustee or such Paying Agent, will be sufficient to pay when due the principal of and interest with respect to this Bond when due, assuming all extensions of credit under the Letter of Credit Agreement outstanding at the time of such deposit were fully drawn.

If an Event of Default (as defined in the Letter of Credit Agreement) shall have occurred under Section 8 of the Letter of Credit Agreement by reason of a failure by the Company to make a payment with respect to any Reimbursement Obligation when the same shall be due and payable (including by acceleration) pursuant to the Loan Documents, it shall be deemed to be an Event of Default, for purposes of Section 10.01 of the Mortgage Indenture, in payment of an amount of principal of this Bond equal to the amount of such unpaid Reimbursement Obligation (but, in no event, in excess of the face amount (maximum principal amount) of this Bond). If an Event of Default (as defined in the Letter of Credit Agreement) shall have occurred under Section 8 of the Letter of Credit Agreement by reason of a failure by the Company to make a payment of any Interest Amount or any other Obligation (other than a Reimbursement Obligation) when the same shall be due and payable (including by acceleration) pursuant to the

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Loan Documents, it shall be deemed to be an Event of Default, for purposes of Section 10.01 of the Mortgage Indenture, in the payment of an amount of interest with respect to this Bond equal to the amount of such unpaid Interest Amount or amount of such other Obligation. The Company’s obligation with respect to this Bond shall be fully satisfied when (and the holder hereof shall surrender this Bond to, or upon the order of, the Company for cancellation) the Letter of Credit Agreement shall have been terminated and all of the Obligations and Interest Amounts then due and payable shall have been duly paid by the Company and all Letters of Credit shall have expired or terminated. At the time of surrender of this Bond, the holder hereof shall deliver such appropriate instruments of transfer or release as may reasonably be requested by the Company.

If an Event of Default shall occur and be continuing as provided in the Mortgage Indenture, the Trustee or the Holders of not less than 25% in aggregate principal amount of Bonds then Outstanding, considered as one class, may declare the principal amount of all Bonds then Outstanding to be due and payable immediately by notice in writing to the Company (and to the Trustee if given by Holders); provided, however, that with respect to certain Events of Default relating to bankruptcy, insolvency and similar events, the principal amount of all Bonds then Outstanding shall be due and payable immediately without further action by the Trustee or the Holders.

The Mortgage Indenture permits, with certain exceptions as therein provided, the Company and the Trustee to enter into one or more supplemental indentures for the purpose of adding any provisions to, or changing in any manner or eliminating any of the provisions of, the Mortgage Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Bonds at the time Outstanding, considered as one class; provided, however, that if there shall be Bonds of more than one series Outstanding under the Mortgage Indenture and if a proposed supplemental indenture shall directly affect the rights of the Holders of Bonds of one or more, but less than all, of such series, then the consent only of the Holders of a majority in aggregate principal amount of the Outstanding Bonds of all series so directly affected, considered as one class, shall be required; and provided, further, that if the Bonds of any series shall have been issued in more than one Tranche and if a proposed supplemental indenture shall directly affect the rights of the Holders of Bonds of one or more, but less than all, of such Tranches, then the consent only of the Holders of a majority in aggregate principal amount of the Outstanding Bonds of all Tranches so directly affected, considered as one class, shall be required; and provided, further, that the Mortgage Indenture permits the Company and the Trustee to enter into one or more supplemental indentures for certain purposes without the consent of any Holders of Bonds; and provided, further, that for the avoidance of doubt, the foregoing shall not change the voting requirements under Section 14.02 of the Mortgage Indenture, which for the avoidance of doubt, require the consent of the Holders of each Outstanding Bond of each series or Tranche in certain circumstances. The Mortgage Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of Bonds, on behalf of the Holders of all such Bonds, to waive certain past defaults under the Mortgage Indenture and their consequences. Any such consent or waiver by the Holder of this Bond shall be conclusive and binding upon such Holder and upon all future Holders of this Bond and of any Bond issued upon the registration of transfer hereof or in exchange herefor or in lieu

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hereof, whether or not notation of such consent or waiver is made upon this Bond. Notwithstanding the foregoing, no supplemental indenture shall amend, modify or waive any provision of Section 10.07 of the Mortgage Indenture without the consent of the Holders.

As provided in and subject to the provisions of the Mortgage Indenture, the Holder of this Bond shall not have the right to institute any proceeding with respect to the Mortgage Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default, the Holders of at least 25% in aggregate principal amount of the Bonds at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity, and the Trustee shall not have received from the Holders of at least a majority in aggregate principal amount of Bonds at the time Outstanding a direction inconsistent with such written request, and shall have failed to institute any such proceeding for 60 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Bond for the enforcement of any payment of principal hereof or interest with respect hereto on or after the respective due dates expressed herein.

No reference herein to the Mortgage Indenture and no provision of this Bond or of the Mortgage Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and interest with respect to this Bond at the times, place and rate, and in the coin or currency, herein prescribed.

For all purposes of the Mortgage Indenture, the principal amount of this Bond Outstanding as of any date of calculation shall be equal to the Obligations outstanding under the Loan Documents as of such date.

This Bond is issuable in the denomination of $100,000,000 or such greater or lesser amount equal to the face amount of this Bond as provided herein.

As provided in the Mortgage Indenture and subject to certain limitations set forth therein and herein, the transfer of this Bond is registrable in the Bond Register, upon surrender of this Bond for registration of transfer at the office or agency of the Company in any place where the principal of and interest with respect to this Bond are payable, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company, the Trustee or the Bond Registrar, as the case may be, duly executed by the Holder hereof or such Holder’s attorney duly authorized in writing, and thereupon one or more new Bonds of this series and of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees.

Before any transfer of this Bond by the Holder or such Holder’s legal representative will be recognized or given effect by the Company or the Trustee, the Holder shall note the then current principal amount payable on this Bond, the interest accrued to the date of such transfer and the then current face amount of this Bond, and shall notify the Company and the Trustee of the name and address of the transferee and shall afford the Company and the Trustee the opportunity of verifying the notation as to such then current principal amount payable on this

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Bond, the interest accrued to the date of such transfer and the then current face amount of this Bond. By acceptance hereof the Holder of this Bond and each transferee shall be deemed to have agreed to indemnify and hold harmless the Company and the Trustee against all losses, claims, damages or liability arising out of any failure on part of the Holder or of any such transferee to comply with the requirements of the preceding sentence.

No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Bond for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Bond is registered as the owner hereof for all purposes, whether or not this Bond be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

This Bond shall be governed by, and construed and enforced in accordance with, the laws of the State of New York without regard to the principles of conflicts of laws thereunder, except to the extent that the Trust Indenture Act shall be applicable.

As provided in the Mortgage Indenture, no recourse shall be had for the payment of the principal of or interest with respect to this Bond, or any part thereof, or for any claim based hereon or otherwise in respect hereof, or of the indebtedness represented hereby, or upon any obligation, covenant or agreement under the Mortgage Indenture, against any incorporator, shareholder, officer or director, as such, past, present or future, of the Company or of any predecessor or successor corporation (either directly or through the Company or a predecessor or successor corporation), whether by virtue of any constitutional provision, statute or rule of law or by the enforcement of any assessment or penalty or otherwise; it being expressly agreed and understood that the Mortgage Indenture and all the Bonds are solely corporate obligations and that any such personal liability is hereby expressly waived and released as a condition of, and as part of the consideration for, the execution of the Mortgage Indenture and the issuance of this Bond.

Anything in this Bond, the Mortgage Indenture, or the Loan Documents to the contrary notwithstanding, any payment by the Company of principal of or interest on this Bond shall be applied by the holder hereof to the payment of any amounts owing by the Company on the Obligations and Interest Amounts that are then due or are to become due, and shall, to the extent of such application, for all purposes, satisfy and discharge the obligation of the Company to make such payment on such Obligations and Interest Amounts, respectively.

Anything in this Bond, the Mortgage Indenture, or the Loan Documents to the contrary notwithstanding, any payment by the Company of the Obligations and Interest Amounts pursuant to the Loan Documents shall, to the extent thereof, for all purposes, satisfy and discharge the obligation of the Company to make a payment of principal or interest, as the case may be, in respect of this Bond that is then due or is to become due.

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SCHEDULE OF INCREASES OR DECREASES IN THE PRINCIPAL AMOUNT OF THE BOND OF THE SIXTY-NINTH SERIES

Date	Amount of Increase in Principal Amount of this Bond	Amount of Decrease in Principal Amount of this Bond	Principal Amount of this Bond following such Increase or Decrease	Signature of Authorized Signatory of the Trustee

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ASSIGNMENT FORM

To assign this Bond, fill in the form below: (1) or (we) assign and transfer this Bond to

(Insert assignee’s soc. sec. or tax I.D. no.)

(Print or type assignee’s name, address and zip code)

and irrevocably appoint

to transfer this Bond on the books of the Company. The agent may substitute another to act for him.

Date:

Your signature:

(Sign exactly as your name appears on the face of this Bond)

Tax Identification No.:

SIGNATURE GUARANTEE:

Signatures must be guaranteed by an “eligible guarantor institution” meeting the requirements of the Bond Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Bond Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.

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SCHEDULE 1

RECORDING INFORMATION

This Schedule 1 is hereby incorporated into and made a part of the Thirty-Second Supplemental Indenture. The Thirty-Second Supplemental Indenture (or a memorandum describing such Thirty-Second Supplemental Indenture) shall be recorded in the Official Records of the County (as defined above) in order to put third parties on record notice with respect thereto.

The Mortgage Indenture was initially recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column A below.

The Memorandum of Supplemental First Mortgage Indentures, dated as of August 12, 2020 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column B below.

Certain parcels of real property located in certain counties have been released from the lien of the Mortgage Indenture, as set forth in the 2020 Partial Release (as defined below). To the extent applicable, the Certificate of Partial Release of Lien, dated as of December 15, 2020 (the “2020 Partial Release”) was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column C below.

The Seventh Supplemental Indenture, dated as of November 16, 2020 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column D below.

The Eighth Supplemental Indenture, dated as of March 11, 2021 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column E below.

Certain parcels of real property located in certain counties have been released from the lien of the Mortgage Indenture, as set forth in the 2021 Partial Release (as defined below). To the extent applicable, the Certificate of Partial Release of Lien, dated as of September 9, 2021 (the “2021 Partial Release”) was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column F below.

The Memorandum of Supplemental First Mortgage Indentures, dated as of August 31, 2021 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column G below.

Sch. 1-1

The Memorandum of Supplemental First Mortgage Indentures, dated as of January 7, 2022 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column H below.

Certain parcels of real property located in certain counties have been released from the lien of the Mortgage Indenture, as set forth in the 2022 Partial Release (as defined below). To the extent applicable, the Certificate of Partial Release of Lien, dated as of March 31, 2022 (the “2022 Partial Release”) was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column I below.

The Memorandum of Supplemental First Mortgage Indentures, dated as of May 13, 2022 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column J below.

The Sixteenth Supplemental Indenture, dated as of June 8, 2022 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column K below.

Certain parcels of real property located in certain counties have been released from the lien of the Mortgage Indenture, as set forth in the 2022-B Partial Release (as defined below). To the extent applicable, the Certificate of Partial Release of Lien, dated as of August 12, 2022 (the “2022-B Partial Release”) was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column L below.

The Seventeenth Supplemental Indenture, dated as of October 4, 2022 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column M below.

The Eighteenth Supplemental Indenture, dated as of January 6, 2023 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column N below.

The Nineteenth Supplemental Indenture, dated as of March 30, 2023 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column O below.

The Twentieth Supplemental Indenture, dated as of June 5, 2023 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column P below.

Certain parcels of real property located in certain counties have been released from the lien of the Mortgage Indenture, as set forth in the 2023 Partial Release (as defined below). To the extent applicable, the Certificate of Partial Release of Lien, dated as of December 15, 2023

Sch. 1-2

(the “2023 Partial Release”) was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column Q below.

The Memorandum of Supplemental First Mortgage Indentures, dated as of December 29, 2023 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column R below.

The Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column S below.

The Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column T below.

The Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column U below.

The Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column V below.

The Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025 was recorded in the Official Records of the County on the applicable recording dates and at the applicable instrument numbers set forth in column W below.

	A	B	C	D
County	Recording Date & Instrument Number<br><br>(Indenture of Mortgage, dated as of June 19, 2020)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 12, 2020)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2020)	Recording Date & Instrument Number<br><br>(Seventh Supplemental Indenture, dated as of November 16, 2020)
Alameda	Date: 7/8/2020<br><br>Instrument: 2020159002	Date: 8/19/2020<br><br>Instrument: 2020203390	-	Date: 3/8/2021<br><br>Instrument: 2021094794
Alpine	Date: 7/8/2020<br><br>Instrument: Ins.000313	Date: 8/21/2020<br><br>Instrument: 2020000409	-	Date: 2/26/2021<br><br>Instrument: 2021-000224
Amador	Date: 7/7/2020<br><br>Instrument: 2020-0005302	Date: 8/19/2020<br><br>Instrument: 2020-0006984-00	-	Date: 3/8/2021<br><br>Instrument: 20210002728
Butte	Date: 7/7/2020<br><br>Instrument: 2020-0026656	Date: 8/19/2020<br><br>Instrument: 2020-0033263	-	Date: 2/24/2021<br><br>Instrument: 2021-0008993
Calaveras	Date: 7/7/2020<br><br>Instrument: 2020-008603	Date: 8/19/2020<br><br>Instrument: 2020-011334	-	Date: 2/24/2021<br><br>Instrument: 2021-003707

Sch. 1-3

	A	B	C	D
County	Recording Date & Instrument Number<br><br>(Indenture of Mortgage, dated as of June 19, 2020)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 12, 2020)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2020)	Recording Date & Instrument Number<br><br>(Seventh Supplemental Indenture, dated as of November 16, 2020)
Colusa	Date: 7/13/2020<br><br>Instrument: 2020-0002012	Date: 8/19/2020<br><br>Instrument: 2020-0002404	-	Date: 2/25/2021<br><br>Instrument: 2021-0000922
Contra Costa	Date: 7/10/2020<br><br>Instrument: 2020-0137967-00	Date: 8/24/2020<br><br>Instrument: 2020-0179597	-	Date: 3/8/2021<br><br>Instrument: 2021-0068856
El Dorado	Date: 7/7/2020<br><br>Instrument: 2020-0033173-00	Date: 8/19/2020<br><br>Instrument: 2020-0042892-00	-	Date: 3/4/2021<br><br>Instrument: 2021-0014976
Fresno	Date: 7/7/2020<br><br>Instrument: 2020-0084490	Date: 8/20/2020<br><br>Instrument: 2020-0108156	-	Date: 2/24/2021<br><br>Instrument: 2021-0031297
Glenn	Date: 7/8/2020<br><br>Instrument: 2020-2622	Date: 8/25/2020<br><br>Instrument: 2020-3320	-	Date: 2/25/2021<br><br>Instrument: 2021-0901
Humboldt	Date: 7/14/2020<br><br>Instrument: 2020-011590	Date: 8/24/2020<br><br>Instrument: 2020-014544	-	Date: 3/5/2021<br><br>Instrument: 2021005120
Kern	Date: 7/7/2020<br><br>Instrument: 220088046	Date: 8/19/2020<br><br>Instrument: 220113312	Date: 12/29/2020<br><br>Instrument: 220202055	Date: 2/24/2021<br><br>Instrument: 221034332
Kings	Date: 7/7/2020<br><br>Instrument: 2011843	Date: 8/21/2020<br><br>Instrument: 2015093	-	Date: 2/24/2021<br><br>Instrument: 2104019
Lake	Date: 7/7/2020<br><br>Instrument: 2020008082	Date: 8/19/2020<br><br>Instrument: 2020010193	-	Date: 2/24/2021<br><br>Instrument: 2021003293
Lassen	Date: 7/8/2020<br><br>Instrument: 2020-02654	Date: 8/20/2020<br><br>Instrument: 2020-03389	-	Date: 2/25/2021<br><br>Instrument: 2021-00982
Madera	Date: 7/7/2020<br><br>Instrument: 2020015446	Date: 8/19/2020<br><br>Instrument: 2020019584	-	Date: 3/9/2021<br><br>Instrument: 2021007361
Marin	Date: 7/7/2020<br><br>Instrument: 2020-0028741	Date: 8/19/2020<br><br>Instrument: 2020-0037600	-	Date: 2/24/2021<br><br>Instrument: 2021-0013112
Mariposa	Date: 7/7/2020<br><br>Instrument: 20202190	Date: 8/20/2020<br><br>Instrument: 20202821	-	Date: 3/4/2021<br><br>Instrument: 20211080
Mendocino	Date: 7/7/2020<br><br>Instrument: 202007917	Date: 8/19/2020<br><br>Instrument: 2020-10112	-	Date: 2/24/2021<br><br>Instrument: 2021-02892
Merced	Date: 7/7/2020<br><br>Instrument: 2020022266	Date: 8/19/2020<br><br>Instrument: 2020028493	-	Date: 2/24/2021<br><br>Instrument: 2021008602
Modoc	Date: 7/7/2020<br><br>Instrument: 20200001804	Date: 8/19/2020<br><br>Instrument: 20200002135	-	Date: 2/24/2021<br><br>Instrument: 20210000422
Monterey	Date: 7/7/2020<br><br>Instrument: 2020032685	Date: 8/19/2020<br><br>Instrument: 2020042185	-	Date: 2/24/2021<br><br>Instrument: 2021014097
Napa	Date: 7/7/2020<br><br>Instrument: 2020-0016006	Date: 8/20/2020<br><br>Instrument: 2020-0020526	-	Date: 3/4/2021<br><br>Instrument: 2021-0008728
Nevada	Date: 7/7/2020<br><br>Instrument: 20200015164	Date: 8/25/2020<br><br>Instrument: 20200020840	-	Date: 3/4/2021<br><br>Instrument: 20210007838

Sch. 1-4

	A	B	C	D
County	Recording Date & Instrument Number<br><br>(Indenture of Mortgage, dated as of June 19, 2020)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 12, 2020)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2020)	Recording Date & Instrument Number<br><br>(Seventh Supplemental Indenture, dated as of November 16, 2020)
Placer	Date: 7/7/2020<br><br>Instrument: 2020-0067740	Date: 8/19/2020<br><br>Instrument: 2020-0087937-00	-	Date: 2/24/2021<br><br>Instrument: 2021-0026083-00
Plumas	Date: 7/9/2020<br><br>Instrument: 2020-0003422	Date: 8/20/2020<br><br>Instrument: 2020-0004742	-	Date: 3/11/2021<br><br>Instrument: 2021-0001758
Sacramento	Date: 7/7/2020<br><br>Instrument: Ins-202007071055	Date: 8/19/2020<br><br>Instrument: 202008190892	-	Date: 2/24/2021<br><br>Instrument: 202102241076
San Benito	Date: 7/7/2020<br><br>Instrument: 2020-0007874	Date: 8/19/2020<br><br>Instrument: 2020-0010072	-	Date: 3/4/2021<br><br>Instrument: 2021-0003400
San Bernardino	Date: 7/7/2020<br><br>Instrument: 2020-0226134	Date: 8/19/2020<br><br>Instrument: 2020-0294961	-	Date: 2/24/2021<br><br>Instrument: 2021-0087782
San Francisco	Date: 7/7/2020<br><br>Instrument: 2020-K949017-00	Date: 8/19/2020<br><br>Instrument: 2020006126	-	Date: 2/24/2021<br><br>Instrument: 2021036477
San Joaquin	Date: 7/7/2020<br><br>Instrument: 2020-080390	Date: 8/19/2020<br><br>Instrument: 2020-103840	-	Date: 2/24/2021<br><br>Instrument: 2021-033997
San Luis Obispo	Date: 7/7/2020<br><br>Instrument: 2020033897	Date: 8/19/2020<br><br>Instrument: 2020043805	Date: 3/5/2021<br><br>Instrument: 2021017044	Date: 3/8/2021<br><br>Instrument: 2021017458
San Mateo	Date: 7/7/2020<br><br>Instrument: 2020064008	Date: 8/21/2020<br><br>Instrument: 2020-084135	-	Date: 2/24/2021<br><br>Instrument: 2021-030961
Santa Barbara	Date: 7/13/2020<br><br>Instrument: 2020-0034969	Date: 8/19/2020<br><br>Instrument: 2020-0043690	-	Date: 2/24/2021<br><br>Instrument: 2021-0014736
Santa Clara	Date: 7/7/2020<br><br>Instrument: 24528422	Date: 8/19/2020<br><br>Instrument: 24580344	-	Date: 2/24/2021<br><br>Instrument: 24845255
Santa Cruz	Date: 7/7/2020<br><br>Instrument: 2020-0024403	Date: 8/19/2020<br><br>Instrument: 2020-0031634	-	Date: 2/24/2021<br><br>Instrument: 2021-0011369
Shasta	Date: 7/7/2020<br><br>Instrument: 2020-0021039	Date: 8/19/2020<br><br>Instrument: 2020-0027008	Date: 12/29/2020<br><br>Instrument: 2020-0047326	Date: 2/24/2021<br><br>Instrument: 2021-0007584
Sierra	Date: 7/9/2020<br><br>Instrument: 2020171226	Date: 8/20/2020<br><br>Instrument: 2020171540	-	Date: 2/25/2021<br><br>Instrument: 2020172589
Solano	Date: 7/7/2020<br><br>Instrument: Ins-202000054277	Date: 8/19/2020<br><br>Instrument: 202000069597	-	Date: 2/24/2021<br><br>Instrument: 202100021149
Sonoma	Date: 7/9/2020<br><br>Instrument: 2020055917	Date: 8/19/2020<br><br>Instrument: 2020070874	-	Date: 2/24/2021<br><br>Instrument: 2021021837
Stanislaus	Date: 7/8/2020<br><br>Instrument: 2020-0047771	Date: 8/19/2020<br><br>Instrument: 2020-0061515-00	-	Date: 2/24/2021<br><br>Instrument: 2021-0017942-00
Sutter	Date: 7/8/2020<br><br>Instrument: 2020-0009800	Date: 8/19/2020<br><br>Instrument: 2020-0012784	-	Date: 2/24/2021<br><br>Instrument: 20210003735

Sch. 1-5

	A	B	C	D
County	Recording Date & Instrument Number<br><br>(Indenture of Mortgage, dated as of June 19, 2020)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 12, 2020)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2020)	Recording Date & Instrument Number<br><br>(Seventh Supplemental Indenture, dated as of November 16, 2020)
Tehama	Date: 7/7/2020<br><br>Instrument: 2020007674	Date: 8/19/2020<br><br>Instrument: 2020009820	-	Date: 2/24/2021<br><br>Instrument: 2021002378
Trinity	Date: 7/8/2020<br><br>Instrument: 202002224	Date: 8/20/2020<br><br>Instrument: 202002748	-	Date: 2/25/2021<br><br>Instrument: 202100581
Tulare	Date: 7/7/2020<br><br>Instrument: 2020-0039416	Date: 8/26/2020<br><br>Instrument: 2020-0049011	-	Date: 3/2/2021<br><br>Instrument: 2021-0015218
Tuolumne	Date: 7/7/2020<br><br>Instrument: 2020007628	Date: 8/19/2020<br><br>Instrument: 2020009759	-	Date: 3/2/2021<br><br>Instrument: 2021003503
Yolo	Date: 7/8/2020<br><br>Instrument: 2020-0020467	Date: 8/19/2020<br><br>Instrument: 2020-0026550	Date: 3/8/2021<br><br>Instrument:<br><br>2021-0009288	Date: 3/8/2021<br><br>Instrument: 2021-0009289
Yuba	Date: 7/8/2020<br><br>Instrument: 2020-010218	Date: 8/19/2020<br><br>Instrument: 2020-012939	-	Date: 2/24/2021<br><br>Instrument: 2021-003119
	E	F	G	H	I
---	---	---	---	---	---
County	Recording Date & Instrument Number<br><br>(Eighth Supplemental Indenture, dated as of March 11, 2021)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of September 9, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 31, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of January 7, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of March 31, 2022)
Alameda	Date: 06/15/2021<br><br>Instrument: 2021215933	--	Date: 09/14/2021<br><br>Instrument: 2021309420	Date: 01/26/2022<br><br>Instrument: 2022017249	-
Alpine	Date: 06/16/2021<br><br>Instrument: 2021000559	--	Date: 09/14/2021<br><br>Instrument: 2021-000769	Date: 01/24/2022<br><br>Instrument: 2022000031	-
Amador	Date: 06/15/2021<br><br>Instrument: 2021-0007084	--	Date: 09/15/2021<br><br>Instrument: 2021-0010656	Date: 01/25/2022<br><br>Instrument: 2022-0000724	-
Butte	Date: 06/17/2021<br><br>Instrument: 2021-0027732	-	Date: 09/10/2021<br><br>Instrument: 2021-0040855	Date: 01/21/2022<br><br>Instrument: 2022-0002347	-
Calaveras	Date: 06/15/2021<br><br>Instrument: 2021-011005	-	Date: 09/16/2021<br><br>Instrument: 2021-016140	Date: 01/21/2022<br><br>Instrument: 2022-001421	-
Colusa	Date: 06/17/2021<br><br>Instrument: 2021-0002508	-	Date: 09/14/2021<br><br>Instrument: 2021-0003762	Date: 01/24/2022<br><br>Instrument: 2022-0000404	-

Sch. 1-6

	E	F	G	H	I
County	Recording Date & Instrument Number<br><br>(Eighth Supplemental Indenture, dated as of March 11, 2021)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of September 9, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 31, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of January 7, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of March 31, 2022)
Contra Costa	Date: 06/15/2021<br><br>Instrument: 2021-0172986	Date: 09/13/2021<br>Instrument: 2021-0254505	Date: 09/22/2021<br><br>Instrument: 2021-0263934	Date: 01/21/2022<br><br>Instrument: 2022-0013443
El Dorado	Date: 06/15/2021<br><br>Instrument: 2021-0039831	-	Date: 09/13/2021<br><br>Instrument: 2021-0058502	Date: 01/21/2022<br><br>Instrument: 2022-0003838	-
Fresno	Date: 06/15/2021<br><br>Instrument: 2021-0097447	-	Date: 09/13/2021<br><br>Instrument: 2021-0148962	Date: 01/24/2022<br><br>Instrument: 2022-0009356	Date: 04/06/2022<br><br>Instrument: 2022-0044515
Glenn	Date: 06/23/2021<br><br>Instrument: 2021-2872	-	Date: 09/10/2021<br><br>Instrument: 2021-4123	Date: 01/24/2022<br><br>Instrument: 2022-0307	-
Humboldt	Date: 06/24/2021<br><br>Instrument: 2021-014188	-	Date: 09/15/2021<br><br>Instrument: 2021-020689	Date: 01/25/2022<br><br>Instrument: 2022-001615	-
Kern	Date: 06/15/2021<br><br>Instrument: 221112026	-	Date: 09/14/2021 <br>Instrument: 221174492	Date: 01/21/2022<br><br>Instrument: 222010906	-
Kings	Date: 06/15/2021<br><br>Instrument: 2113322	-	Date: 09/17/2021<br><br>Instrument: 2120473	Date: 02/01/2022<br><br>Instrument: 2202147	-
Lake	Date: 06/16/2021<br><br>Instrument: 2021010225	-	Date: 09/13/2021<br><br>Instrument: 2021-015134	Date: 02/02/2022<br><br>Instrument: 2022001154	-
Lassen	Date: 06/18/2021<br><br>Instrument: 2021-03286	-	Date: 09/13/2021<br><br>Instrument: 2021-04857	Date: 01/24/2022<br><br>Instrument: 2022-00332	-
Madera	Date: 06/15/2021<br><br>Instrument: 2021019093	-	Date: 09/10/2021<br><br>Instrument: 2021028583	Date: 01/21/2022<br><br>Instrument: 2022001843	-
Marin	Date: 06/15/2021<br><br>Instrument: 2021-0039212	-	Date: 09/10/2021<br><br>Instrument: 2021-0056705	Date: 01/21/2022<br><br>Instrument: 2022-0002727	Date: 04/06/2022<br><br>Instrument: 2022-0014733
Mariposa	Date: 06/15/2021<br><br>Instrument: 20212780	-	Date: 09/23/2021<br><br>Instrument: 20214302	Date: 02/01/2022<br><br>Instrument: 20220454	-
Mendocino	Date: 06/16/2021<br><br>Instrument: 2021-09192	-	Date: 09/17/2021<br><br>Instrument: 2021-14137	Date: 01/25/2022<br><br>Instrument: 2022-01242	-
Merced	Date: 06/15/2021<br><br>Instrument: 2021026546	-	Date: 09/13/2021<br><br>Instrument: 2021040766	Date: 01/21/2022<br><br>Instrument: 2022003686	-
Modoc	Date: 06/15/2021<br><br>Instrument: 20210001695	-	Date: 09/10/2021<br><br>Instrument: 20210002777	Date: 01/21/2022<br><br>Instrument: 20220000144	-

Sch. 1-7

	E	F	G	H	I
County	Recording Date & Instrument Number<br><br>(Eighth Supplemental Indenture, dated as of March 11, 2021)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of September 9, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 31, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of January 7, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of March 31, 2022)
Monterey	Date: 06/17/2021<br><br>Instrument: 2021042424	-	Date: 09/13/2021<br><br>Instrument: 2021061137	Date: 01/24/2022<br><br>Instrument: 2022003479	-
Napa	Date: 06/15/2021<br><br>Instrument: 2021-0020222	-	Date: 09/13/2021<br><br>Instrument: 2021-0029107	Date: 01/25/2022<br><br>Instrument: 2022-0001607	-
Nevada	Date: 06/15/2021<br><br>Instrument: 20210020480	-	Date: 09/13/2021<br><br>Instrument: 20210030075	Date: 01/27/22<br><br>Instrument: 20220002043	Date: 03/31/2022<br><br>Instrument: 20220007109
Placer	Date: 06/15/2021<br><br>Instrument: 2021-0077769-00	-	Date: 09/10/2021<br><br>Instrument: 2021-0114356-00	Date: 01/25/2022<br><br>Instrument: 2022-0007227-00	Date: 03/31/2022<br><br>Instrument: 2022-0027849-00
Plumas	Date: 06/18/2021<br><br>Instrument: 2021-4121	Date: 09/21/2021<br>Instrument: 2021-0006513	Date: 09/24/2021<br><br>Instrument: 2021-0006605	Date: 01/24/2022<br><br>Instrument: 2022-0000507	-
Sacramento	Date: 06/18/2021<br><br>Instrument: 202106180534	-	Date: 09/13/2021<br><br>Instrument: 202109130797	Date: 01/21/2022<br><br>Instrument: 202201211306	-
San Benito	Date: 06/23/2021<br><br>Instrument: 2021-0009669	-	Date: 09/20/2021<br><br>Instrument: 2021-0014111	Date: 01/21/2022<br><br>Instrument: 2022-0000812	-
San Bernardino	Date: 06/15/2021<br><br>Instrument: 2021-0270300	-	Date: 09/10/2021<br><br>Instrument: 2021-0414379	Date: 01/21/2022<br><br>Instrument: 2022-0026583	-
San Francisco	Date: 06/16/2021<br><br>Instrument: 2021096597	-	Date: 09/20/2021<br><br>Instrument: 2021147122	Date: 01/28/2022<br><br>Instrument: 2022010094	-
San Joaquin	Date: 06/15/2021<br><br>Instrument: 2021-102076	-	Date: 09/10/2021<br><br>Instrument: 2021-152907	Date: 01/21/2022<br><br>Instrument: 2022-009240	-
San Luis Obispo	Date: 06/15/2021<br><br>Instrument: 2021042772	-	Date: 09/10/2021<br><br>Instrument: 2021062407	Date: 01/24/2022<br><br>Instrument: 2022003310	-
San Mateo	Date: 06/15/2021<br><br>Instrument: 2021-090929	-	Date: 09/14/2021<br><br>Instrument: 2021-132011	Date: 01/24/2022<br><br>Instrument: 2022-006389	Date: 04/07/2022<br><br>Instrument: 2022-029645
Santa Barbara	Date: 06/16/2021<br><br>Instrument: 2021-0045121	-	Date: 09/15/2021<br><br>Instrument: 2021-0065545	Date: 01/24/2022<br><br>Instrument: 2022-0004075	-
Santa Clara	Date: 06/15/2021<br><br>Instrument: 24996810	Date: 09/21/2021<br><br>Instrument: 25107264	Date: 09/22/2021<br><br>Instrument: 25109534	Date: 01/24/2022<br><br>Instrument: 25224313	Date: 04/07/2022<br><br>Instrument: 25277354

Sch. 1-8

	E	F	G	H	I
County	Recording Date & Instrument Number<br><br>(Eighth Supplemental Indenture, dated as of March 11, 2021)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of September 9, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of August 31, 2021)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of January 7, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of March 31, 2022)
Santa Cruz	Date: 06/15/2021<br><br>Instrument: 2021-0032793	-	Date: 09/10/2021<br><br>Instrument: 2021-0046780	Date: 01/21/2022<br><br>Instrument: 2022-0002159	-
Shasta	Date: 06/15/2021<br><br>Instrument: 2021-0024897	Date: 09/20/2021<br>Instrument: 2021-0039149	Date: 09/22/2021<br><br>Instrument: 2021-0039480	Date: 01/21/2022<br><br>Instrument: 2022-0002199	Date: 04/06/2022<br><br>Instrument: 2022-0011169
Sierra	Date: 06/17/2021<br><br>Instrument: 2021173017	-	Date: 09/14/2021<br><br>Instrument: 2021173609	Date: 01/26/2022<br><br>Instrument: 2022174179	-
Solano	Date: 06/15/2021<br><br>Instrument: 202100064487	--	Date: 09/10/2021<br><br>Instrument: 202100095898	Date: 01/24/2022<br><br>Instrument: 202200005916	-
Sonoma	Date: 06/15/2021<br><br>Instrument: 2021070076	-	Date: 09/13/2021<br><br>Instrument: 2021102595	Date: 01/24/2022<br><br>Instrument: 2022004991	-
Stanislaus	Date: 06/16/2021<br><br>Instrument: 2021-0057206	--	Date: 10/05/2021<br><br>Instrument: 2021-0093766	Date: 02/02/2022<br><br>Instrument: 2022-0007967	-
Sutter	Date: 06/17/2021<br><br>Instrument: 2021-0011236	-	Date: 09/29/2021<br><br>Instrument: 2021-0017681	Date: 01/25/2022<br><br>Instrument: 2022-0001163	-
Tehama	Date: 06/15/2021<br><br>Instrument: 2021008603	-	Date: 09/10/2021<br><br>Instrument: 2021012840	Date: 01/21/2022<br><br>Instrument: 2022000860	-
Trinity	Date: 06/17/2021<br><br>Instrument: 202101938	-	Date: 09/13/2021<br><br>Instrument: 202105327	Date: 01/24/2022<br><br>Instrument: 202200200	-
Tulare	Date: 06/15/2021<br><br>Instrument: 2021-0043754	-	Date: 09/10/2021<br><br>Instrument: 2021-0066763	Date: 02/25/2022<br><br>Instrument: 2022-0005026	-
Tuolumne	Date: 06/17/2021<br><br>Instrument: 2021009478	-	Date: 09/10/2021<br><br>Instrument: 2021014302	Date: 01/24/2022<br><br>Instrument: 2022000979	-
Yolo	Date: 06/16/2021<br><br>Instrument: 2021-0023598	-	Date: 09/10/2021<br><br>Instrument: 2021-0034493	Date: 01/24/2022<br><br>Instrument: 2022-0001936	-
Yuba	Date: 06/15/2021<br><br>Instrument: 2021-010827	-	Date: 09/10/2021<br><br>Instrument: 2021-016949	Date: 01/24/2022<br><br>Instrument: 2022-001131	-

Sch. 1-9

	J	K	L	M	N
County	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of May 13, 2022)	Recording Date & Instrument Number<br><br>(Sixteenth Supplemental Indenture, dated as of June 8, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of August 12, 2022)	Recording Date & Instrument Number<br><br>(Seventeenth Supplemental Indenture, dated as of October 4, 2022)	Recording Date & Instrument Number<br><br>(Eighteenth Supplemental Indenture, dated as of January 6, 2023)
Alameda	Date: 05/25/2022<br><br>Instrument: 2022100365	Date: 08/05/22<br><br>Instrument: 2022138829	-	Date: 11/16/2022<br><br>Instrument: 2022186172	Date: 3/22/2023<br><br>Instrument: 2023033135
Alpine	Date: 05/20/2022<br><br>Instrument: 2022000254	Date: 08/10/22<br><br>Instrument: 2022000389	-	Date: 11/17/2022<br><br>Instrument: 2022000569	Date: 3/15/2023<br><br>Instrument: 2023000173
Amador	Date: 05/23/2022<br><br>Instrument: 2022-0004637	Date: 08/10/22<br><br>Instrument: 2022-0006870	-	Date: 11/18/2022<br><br>Instrument: 2022-0009747	Date: 3/16/2023<br><br>Instrument: 2023-0001359
Butte	Date: 05/18/2022<br><br>Instrument: 2022-0017492	Date: 08/05/22<br><br>Instrument: 2022-0026101	-	Date:11/16/2022<br><br>Instrument:2022-0036889	Date: 3/13/2023<br><br>Instrument: 2023-0007192
Calaveras	Date: 05/24/2022<br><br>Instrument: 2022-006931	Date: 08/05/22<br><br>Instrument: 2022-009868	-	Date: 11/16/2022<br><br>Instrument: 2022-013219	Date: 3/13/2023<br><br>Instrument: 2023-001718
Colusa	Date: 05/20/2022<br><br>Instrument: 2022-0001852	Date: 08/09/22<br><br>Instrument: 2022-0002621	-	Date: 11/22/2022<br><br>Instrument: 2022-0003593	Date: 3/16/2023<br><br>Instrument: 2023-0000721
Contra Costa	Date: 05/24/2022<br><br>Instrument: 2022-0087997	Date: 08/05/22<br><br>Instrument: 2022-0123193	-	Date: 11/17/2022<br><br>Instrument: 2022-0174703	Date: 3/13/2023<br><br>Instrument: 2023-0023272
El Dorado	Date: 05/18/2022<br><br>Instrument: 2022-0022236	Date: 08/05/22<br><br>Instrument: 2022-0032806	-	Date: 11/16/2022<br><br>Instrument: 2022-0043861	Date: 3/13/2023<br><br>Instrument: 2023-0006917
Fresno	Date: 05/24/2022<br><br>Instrument: 2022-0069162	Date: 08/05/22<br><br>Instrument: 2022-0099615	-	Date: 11/16/2022<br><br>Instrument: 2022-0139802	Date: 3/13/2023<br><br>Instrument: 2023-0022360
Glenn	Date: 05/18/2022<br><br>Instrument: 2022-1984	Date: 08/05/22<br><br>Instrument: 2022-3049	-	Date: 11/16/2022<br><br>Instrument: 2022-4524	Date: 3/13/2023<br><br>Instrument: 2023-0702
Humboldt	Date: 05/23/2022<br><br>Instrument: 2022-010058	Date: 08/05/22<br><br>Instrument: 2022-014652	-	Date: 11/16/2022<br><br>Instrument: 2022-019960	Date: 3/13/2023<br><br>Instrument: 2023-003116
Kern	Date: 05/24/2022<br><br>Instrument: 222082073	Date: 08/05/22<br><br>Instrument: 222121822	Date: 08/18/2022<br>Instrument: 222127316	Date: 11/16/2022<br><br>Instrument: 222171366	Date: 3/13/2023<br><br>Instrument: 223028449
Kings	Date: 06/03/2022<br><br>Instrument: 2022-2210786	Date: 08/10/22<br><br>Instrument: 2215025	-	Date: 11/22/2022<br><br>Instrument: 2222370	Date: 3/14/2023<br><br>Instrument: 2303989
Lake	Date: 05/20/2022<br><br>Instrument: 2022007278	Date: 08/09/22<br><br>Instrument: 2022010807	-	Date: 11/21/2022<br><br>Instrument: 2022015365	Date: 3/17/2023<br><br>Instrument: 2023003147

Sch. 1-10

	J	K	L	M	N
County	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of May 13, 2022)	Recording Date & Instrument Number<br><br>(Sixteenth Supplemental Indenture, dated as of June 8, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of August 12, 2022)	Recording Date & Instrument Number<br><br>(Seventeenth Supplemental Indenture, dated as of October 4, 2022)	Recording Date & Instrument Number<br><br>(Eighteenth Supplemental Indenture, dated as of January 6, 2023)
Lassen	Date: 05/20/2022<br><br>Instrument: 202202323	Date: 08/09/22<br><br>Instrument: 2022-03518	-	Date: 11/21/2022<br><br>Instrument: 2022-04959	Date: 3/15/2023<br><br>Instrument: 2023-00661
Madera	Date: 05/18/2022<br><br>Instrument: 2022013676	Date: 08/05/22<br><br>Instrument: 2022020642	-	Date: 11/16/2022<br><br>Instrument: 2022029180	Date: 3/13/2023<br><br>Instrument: 2023004536
Marin	Date: 05/18/2022<br><br>Instrument: 2022-0020238	Date: 08/05/22<br><br>Instrument: 2022-0028836	-	Date: 11/16/2022<br><br>Instrument: 2022-0037846	Date: 3/13/2023<br><br>Instrument: 2023-0005029
Mariposa	Date: 05/23/2022<br><br>Instrument: 20222048	Date: 08/09/22<br><br>Instrument: 20222965	-	Date: 11/18/2022<br><br>Instrument: 20223991	Date: 3/16/2023<br><br>Instrument: 20230573
Mendocino	Date: 06/03/2022<br><br>Instrument: 2022-07008	Date: 08/10/22<br><br>Instrument: 2022-09549	-	Date: 11/21/2022<br><br>Instrument: 2022-12958	Date: 3/15/2023<br><br>Instrument: 2023-02020
Merced	Date: 05/18/2022<br><br>Instrument: 2022019388	Date: 08/05/22<br><br>Instrument: 2022028723	-	Date: 11/16/2022<br><br>Instrument: 2022038776	Date: 3/21/2023<br><br>Instrument: 2023006148
Modoc	Date: 05/18/2022<br><br>Instrument: 20220000978	Date: 08/05/22<br><br>Instrument: 20220001810	-	Date: 11/16/2022<br><br>Instrument: 20220003071	Date: 3/13/2023<br><br>Instrument: 20230000385
Monterey	Date: 05/25/2022<br><br>Instrument: 2022024181	Date: 08/05/22<br><br>Instrument: 2022033420	-	Date: 11/30/2022<br><br>Instrument: 2022050216	Date: 3/14/2023<br><br>Instrument: 2023007515
Napa	Date: 05/24/2022<br><br>Instrument: 2022-0010514	Date: 08/08/22<br><br>Instrument: 2022-0015081	-	Date: 11/18/2022<br><br>Instrument: 2022-0020800	Date: 3/13/2023<br><br>Instrument: 2023-0004483
Nevada	Date: 05/18/2022<br><br>Instrument: 20220010774	Date: 08/05/22<br><br>Instrument: 20220016121	-	Date: 11/16/2022<br><br>Instrument: 20220022607	Date: 3/13/2023<br><br>Instrument: 20230003143
Placer	Date: 05/18/2022<br><br>Instrument: 2022-0042292-00	Date: 08/05/22<br><br>Instrument: 2022-0062679-00	-	Date: 11/16/2022<br><br>Instrument: 2022-0085376-00	Date: 3/13/2023<br><br>Instrument: 2023-0011889-00
Plumas	Date: 05/18/2022<br><br>Instrument: 2022-0003099	Date: 08/05/22<br><br>Instrument: 2022-0004592	-	Date: 11/16/2022<br><br>Instrument: 2022-0006421	Date: 3/13/2023<br><br>Instrument: 2023-0000790
Sacramento	Date: 05/24/2022<br><br>Instrument: 202205240418	Date: 08/05/22<br><br>Instrument: 202208050870	-	Date: 11/16/2022<br><br>Instrument: 202211160487	Date: 3/28/2023<br><br>Instrument: 202303280021
San Benito	Date: 05/18/2022<br><br>Instrument: 2022-0005300	Date: 08/25/22<br><br>Instrument: 2022-0007992	-	Date: 11/16/2022<br><br>Instrument: 2022-0010013	Date: 3/14/2023<br><br>Instrument: 2023-0001557

Sch. 1-11

	J	K	L	M	N
County	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of May 13, 2022)	Recording Date & Instrument Number<br><br>(Sixteenth Supplemental Indenture, dated as of June 8, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of August 12, 2022)	Recording Date & Instrument Number<br><br>(Seventeenth Supplemental Indenture, dated as of October 4, 2022)	Recording Date & Instrument Number<br><br>(Eighteenth Supplemental Indenture, dated as of January 6, 2023)
San Bernardino	Date: 05/18/2022<br><br>Instrument: 2022-0184555	Date: 08/05/22<br><br>Instrument: 2022-0271632	-	Date: 11/16/2022<br><br>Instrument: 2022-0374949	Date: 3/13/2023<br><br>Instrument: 2023-0059546
San Francisco	Date: 05/24/2022<br><br>Instrument: 2022052240	Date: 08/22/22<br><br>Instrument: 2022079527	-	Date: 12/02/2022<br><br>Instrument: 2022108546	Date: 3/23/2023<br><br>Instrument: 2023021283
San Joaquin	Date: 05/24/2022<br><br>Instrument: 2022-065791	Date: 08/05/22<br><br>Instrument: 2022-093830	-	Date: 11/18/2022<br><br>Instrument: 2022-130609	Date: 03/21/2023<br><br>Instrument: 2023-021829
San Luis Obispo	Date: 05/18/2022<br><br>Instrument: 2022021410	Date: 08/05/22<br><br>Instrument: 2022032062	-	Date: 11/16/2022<br><br>Instrument: 2022045019	Date: 3/13/2023<br><br>Instrument: 2023006723
San Mateo	Date: 05/18/2022<br><br>Instrument: 2022-041210	Date: 08/08/22<br><br>Instrument: 2022-059330	-	Date: 11/16/2022<br><br>Instrument: 2022-079380	Date: 3/27/2023<br><br>Instrument: 2023-013468
Santa Barbara	Date: 05/18/2022<br><br>Instrument: 2022-0024575	Date: 08/08/22<br><br>Instrument: 2022-0035155	-	Date: 11/16/2022<br><br>Instrument: 2022-0047931	Date: 3/21/2023<br><br>Instrument: 2023-0007944
Santa Clara	Date: 05/18/2022<br><br>Instrument: 25304880	Date: 08/08/22<br><br>Instrument: 25354494	-	Date: 11/16/2022<br><br>Instrument: 25400909	Date: 3/13/2023<br><br>Instrument: 25448609
Santa Cruz	Date: 05/18/2022<br><br>Instrument: 2022-0015672	Date: 08/05/22<br><br>Instrument: 2022-0022596	-	Date: 11/16/2022<br><br>Instrument: 2022-0030816	Date: 3/13/2023<br><br>Instrument: 2023-0004221
Shasta	Date: 05/18/2022<br><br>Instrument: 2022-0015875	Date: 08/05/22<br><br>Instrument: 2022-0023892	-	Date: 11/16/2022<br><br>Instrument: 2022-0034632	Date: 3/13/2023<br><br>Instrument: 2023-0005017
Sierra	Date: 05/20/2022<br><br>Instrument: 2022174496	Date: 08/08/22<br><br>Instrument: 2022174749	-	Date: 11/17/2022<br><br>Instrument: 2022175351	Date: 3/15/2023<br><br>Instrument: 2023176040
Solano	Date: 05/18/2022<br><br>Instrument: 202200035505	Date: 08/08/22<br><br>Instrument: 202200052559	-	Date: 11/16/2022<br><br>Instrument: 202200072976	Date: 3/13/2023<br><br>Instrument: 202300010133
Sonoma	Date: 05/18/2022<br><br>Instrument: 2022035095	Date: 08/05/22<br><br>Instrument: 2022052874	-	Date: 11/16/2022<br><br>Instrument: 2022074196	Date: 3/13/2023<br><br>Instrument: 2023010314
Stanislaus	Date: 06/13/2022<br><br>Instrument: 2022-0042714	Date: 08/11/22<br><br>Instrument: 2022-0055142	-	Date: 11/23/2022<br><br>Instrument: 2022-0075478	Date: 3/29/2023<br><br>Instrument: 2023-0013999
Sutter	Date: 05/23/2022<br><br>Instrument: 2022-0007448	Date: 08/12/22<br><br>Instrument: 2022-0011134	-	Date: 11/18/2022<br><br>Instrument: 2022-0015136	Date: 3/16/2023<br><br>Instrument: 2023-0002240

Sch. 1-12

	J	K	L	M	N
County	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of May 13, 2022)	Recording Date & Instrument Number<br><br>(Sixteenth Supplemental Indenture, dated as of June 8, 2022)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of August 12, 2022)	Recording Date & Instrument Number<br><br>(Seventeenth Supplemental Indenture, dated as of October 4, 2022)	Recording Date & Instrument Number<br><br>(Eighteenth Supplemental Indenture, dated as of January 6, 2023)
Tehama	Date: 05/18/2022<br><br>Instrument: 2022006372	Date: 08/05/22<br><br>Instrument: 2022009472	-	Date: 11/16/2022<br><br>Instrument: 2022013471	Date: 3/13/2023<br><br>Instrument: 2023001981
Trinity	Date: 05/20/2022<br><br>Instrument: 202201347	Date: 08/09/22<br><br>Instrument: 202202621	-	Date: 11/18/2022<br><br>Instrument: 202203688	Date: 3/16/2023<br><br>Instrument: 202301165
Tulare	Date: 05/18/2022<br><br>Instrument: 2022-0031627	Date: 08/08/22<br><br>Instrument: 2022-0050147	-	Date: 11/16/2022<br><br>Instrument: 2022-0070659	Date: 3/30/2023<br><br>Instrument: 2023-0014874
Tuolumne	Date: 05/18/2022<br><br>Instrument: 2022006308	Date: 08/08/22<br><br>Instrument: 2022009386	-	Date: 11/16/2022<br><br>Instrument: 2022013139	Date: 3/13/2023<br><br>Instrument: 2023001860
Yolo	Date: 05/18/2022<br><br>Instrument: 2022-0012366	Date: 08/08/22<br><br>Instrument: 2022-0018489	-	Date: 11/16/2022<br><br>Instrument: 2022-0025371	Date: 3/13/2023<br><br>Instrument: 2023-0003662
Yuba	Date: 05/18/2022<br><br>Instrument: 2022-008109	Date: 08/08/22<br><br>Instrument: 2022-012051	-	Date: 11/16/2022<br><br>Instrument: 2022-017124	Date: 3/13/2023<br><br>Instrument: 2023-002484
	O	P	Q	R	S
---	---	---	---	---	---
County	Recording Date & Instrument Number<br><br>(Nineteenth Supplemental Indenture, dated as of March 30, 2023)	Recording Date & Instrument Number<br><br>(Twentieth Supplemental Indenture, dated as of June 5, 2023)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2023)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of December 29, 2023)	Recording Date & Instrument Number<br><br>(Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024)
Alameda	Date: 06/05/2023<br><br>Instrument: 2023063521	Date: 08/21/2023<br><br>Instrument: 2023094821	Date: 12/18/2023<br><br>Instrument: 2023147380	Date: 01/18/2024<br><br>Instrument: 2024010299	Date: 05/03/2024 Instrument: 2024057077
Alpine	Date: 06/08/2023<br><br>Instrument: 2023000270	Date: 08/18/2023<br><br>Instrument: 2023000373	-	Date: 01/22/2024<br><br>Instrument: 2024000031	Date: 05/07/2024 Instrument: 2024000165
Amador	Date: 06/06/2023<br><br>Instrument: 2023-0003053	Date: 08/21/2023<br><br>Instrument: 2023-0004824	-	Date: 01/23/2024<br><br>Instrument: 2024-0000450	Date: 05/20/2024<br><br>Instrument: 2024-0002698
Butte	Date: 06/02/2023<br><br>Instrument: 2023-0014604	Date: 08/17/2023<br><br>Instrument: 2023-0021588	-	Date: 01/18/2024<br><br>Instrument: 2024-0002578	Date: 05/03/2024 Instrument: 2024-0012006
Calaveras	Date: 06/02/2023<br><br>Instrument: 2023-004011	Date: 08/17/2023<br><br>Instrument: 2023-006340	-	Date: 01/18/2024<br><br>Instrument: 2024-000405	Date: 05/03/2024 Instrument: 2024-003520
Colusa	Date: 06/05/2023<br><br>Instrument: 2023-0001388	Date: 08/18/2023<br><br>Instrument: 2023-0002066	-	Date: 01/23/2024<br><br>Instrument: 2024-0000213	Date: 05/06/2024 Instrument: 2024-0001084

Sch. 1-13

	O	P	Q	R	S
County	Recording Date & Instrument Number<br><br>(Nineteenth Supplemental Indenture, dated as of March 30, 2023)	Recording Date & Instrument Number<br><br>(Twentieth Supplemental Indenture, dated as of June 5, 2023)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2023)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of December 29, 2023)	Recording Date & Instrument Number<br><br>(Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024)
Contra Costa	Date: 06/02/2023<br><br>Instrument: 2023-0052597	Date: 08/17/2023<br><br>Instrument: 2023-0079149	-	Date: 01/24/2024<br><br>Instrument: 2024-0007758	Date: 05/16/2024 Instrument: 2024-0045970
El Dorado	Date: 06/02/2023<br><br>Instrument: 2023-0015170	Date: 08/17/2023<br><br>Instrument: 2023-0023087	-	Date: 01/26/2024<br><br>Instrument: 2024-0001966	Date: 05/03/2024 Instrument: 2024-0012542
Fresno	Date: 06/02/2023<br><br>Instrument: 2023-0051499	Date: 08/17/2023<br><br>Instrument: 2023-0075938	-	Date: 01/18/2024<br><br>Instrument: 2024-0004193	Date: 05/03/2024 Instrument: 2024-0040106
Glenn	Date: 06/02/2023<br><br>Instrument: 2023-1625	Date: 08/17/2023<br><br>Instrument: 2023-2449	-	Date: 01/18/2024<br><br>Instrument: 2024-0149	Date: 05/03/2024 Instrument: 2024-1120
Humboldt	Date: 06/12/2023<br><br>Instrument: 2023-007527	Date: 08/17/2023<br><br>Instrument: 2023-010967	-	Date: 01/23/2024<br><br>Instrument: 2024-001013	Date: 05/15/2024 Instrument: 2024-006138
Kern	Date: 06/02/2023<br><br>Instrument: 223064355	Date: 08/17/2023<br><br>Instrument: 223098205	-	Date: 01/22/2024<br><br>Instrument: 224007837	Date: 05/03/2024 Instrument: 224051539
Kings	Date: 06/06/2023<br><br>Instrument: 2308178	Date: 08/18/2023<br><br>Instrument: 2312194	-	Date: 01/23/2024<br><br>Instrument: 2401118	Date: 05/08/2024<br><br>Instrument: 2406036
Lake	Date: 06/06/2023<br><br>Instrument: 2023006124	Date: 08/18/2023<br><br>Instrument: 2023009039	-	Date: 01/23/2024<br><br>Instrument: 2024000703	Date: 05/06/2024 Instrument: 2024004609
Lassen	Date: 06/06/2023<br><br>Instrument: 2023-01576	Date: 08/21/2023<br><br>Instrument: 2023-02503	-	Date: 01/23/2024<br><br>Instrument: 2024-00162	Date: 05/07/2024 Instrument: 2024-01261
Madera	Date: 06/02/2023<br><br>Instrument: 2023010320	Date: 08/17/2023<br><br>Instrument: 2023015614	-	Date: 01/18/2024<br><br>Instrument: 2024001084	Date: 05/03/2024 Instrument: 2024008802
Marin	Date: 06/02/2023<br><br>Instrument: 2023-0013933	Date: 08/17/2023<br><br>Instrument: 2023-0020499	-	Date: 01/24/2024<br><br>Instrument: 2024-0002148	Date: 05/03/2024 Instrument: 2024-0012795
Mariposa	Date: 06/07/2023<br><br>Instrument: 20231363	Date: 08/21/2023<br><br>Instrument: 20232142	-	Date: 01/29/2024<br><br>Instrument: 20240215	Date: 05/07/2024 Instrument: 20241083
Mendocino	Date: 06/06/2023<br><br>Instrument: 2023-04403	Date: 08/21/2023<br><br>Instrument: 2023-06606	-	Date: 01/29/2024<br><br>Instrument: 2024-00767	Date: 05/08/2024 Instrument: 2024-03770
Merced	Date: 06/02/2023<br><br>Instrument: 2023012316	Date: 08/17/2023<br><br>Instrument: 2023019368	-	Date: 01/18/2024<br><br>Instrument: 2024001260	Date: 05/03/2024<br><br>Instrument: 2024010008
Modoc	Date: 06/02/2023<br><br>Instrument: 20230000882	Date: 08/17/2023<br><br>Instrument: 20230001733	-	Date: 01/18/2024<br><br>Instrument: 20240000147	Date: 05/03/2024 Instrument: 20240000816
Monterey	Date: 06/12/2023<br><br>Instrument: 2023017636	Date: 08/17/2023<br><br>Instrument: 2023025534	-	Date: 01/31/2024<br><br>Instrument: 2024003352	Date: 05/03/2024 Instrument: 2024015659
Napa	Date: 06/05/2023<br><br>Instrument: 2023-0008336	Date: 08/17/2023<br><br>Instrument: 2023-0012033	-	Date: 01/22/2024<br><br>Instrument: 2024-0000843	Date: 05/17/2024 Instrument: 2024-0007033

Sch. 1-14

	O	P	Q	R	S
County	Recording Date & Instrument Number<br><br>(Nineteenth Supplemental Indenture, dated as of March 30, 2023)	Recording Date & Instrument Number<br><br>(Twentieth Supplemental Indenture, dated as of June 5, 2023)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2023)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of December 29, 2023)	Recording Date & Instrument Number<br><br>(Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024)
Nevada	Date: 06/05/2023<br><br>Instrument: 20230007116	Date: 08/17/2023<br><br>Instrument: 20230011194	-	Date: 01/18/2024<br><br>Instrument: 20240001002	Date: 05/06/2024<br><br>Instrument: 20240006667
Placer	Date: 06/02/2023<br><br>Instrument: 2023-0028858-00	Date: 08/17/2023<br><br>Instrument: 2023-0043787-00	-	Date: 01/18/2024<br><br>Instrument: 2024-0002444-00	Date: 05/15/2024 Instrument: 2024-0025145-00
Plumas	Date: 06/02/2023<br><br>Instrument: 2023-0002170	Date: 08/17/2023<br><br>Instrument: 2023-0003290	-	Date: 01/18/2024<br><br>Instrument: 2024-0000151	Date: 05/15/2024 Instrument: 2024-0001804
Sacramento	Date: 06/12/2023<br><br>Instrument: 202306120260	Date: 08/17/2023<br><br>Instrument: 202308170355	Date: 12/15/2023<br><br>Instrument: 202312150887	Date: 01/18/2024<br><br>Instrument: 202401180626	Date: 05/15/2024 Instrument: 202405150402
San Benito	Date: 06/13/2023<br><br>Instrument: 2023-0003781	Date: 08/17/2023<br><br>Instrument: 2023-0005296	-	Date: 01/18/2024<br><br>Instrument: 2024-0000381	Date: 05/03/2024<br><br>Instrument: 2024-0002707
San Bernardino	Date: 06/12/2023<br><br>Instrument: 2023-0144099	Date: 08/24/2023<br><br>Instrument: 2023-0208019	-	Date: 01/25/2024<br><br>Instrument: 2024-0019469	Date: 05/15/2024 Instrument: 2024-0112790
San Francisco	Date: 06/06/2023<br><br>Instrument: 2023039990	Date: 08/21/2023<br><br>Instrument: 2023061559	-	Date: 02/05/2024<br><br>Instrument: 2024012710	Date: 05/20/2024 Instrument: 2024039636
San Joaquin	Date: 06/02/2023<br><br>Instrument: 2023-043341	Date: 08/17/2023<br><br>Instrument: 2023-065168	-	Date: 01/18/2024<br><br>Instrument: 2024-004712	Date: 05/03/2024 Instrument: 2024-036976
San Luis Obispo	Date: 06/05/2023<br><br>Instrument: 2023015504	Date: 08/17/2023<br><br>Instrument: 2023024299	-	Date: 01/18/2024<br><br>Instrument: 2024001471	Date: 05/03/2024<br><br>Instrument: 2024011840
San Mateo	Date: 06/05/2023<br><br>Instrument: 2023-026373	Date: 08/17/2023<br><br>Instrument: 2023-039746	-	Date: 01/18/2024<br><br>Instrument: 2024-003045	Date: 05/15/2024 Instrument: 2024-025525
Santa Barbara	Date: 06/05/2023<br><br>Instrument: 2023-0015840	Date: 08/18/2023<br><br>Instrument: 2023-0024097	-	Date: 01/19/2024<br><br>Instrument: 2024-0001800	Date: 05/06/2024 Instrument: 2024-0013446
Santa Clara	Date: 06/05/2023<br><br>Instrument: 25483457	Date: 08/17/2023<br><br>Instrument: 25519458	-	Date: 01/18/2024<br><br>Instrument: 25587760	Date: 05/06/2024 Instrument: 25632491
Santa Cruz	Date: 06/05/2023<br><br>Instrument: 2023-0009819	Date: 08/17/2023<br><br>Instrument: 2023-0015485	-	Date: 01/18/2024<br><br>Instrument: 2024-0000987	Date: 05/06/2024<br><br>Instrument: 2024-0008307
Shasta	Date: 06/05/2023<br><br>Instrument: 2023-0011609	Date: 08/17/2023<br><br>Instrument: 2023-0017774	-	Date: 01/23/2024<br><br>Instrument: 2024-0001432	Date: 05/06/2024 Instrument: 2024-0009067
Sierra	Date: 06/05/2023<br><br>Instrument: 2023176236	Date: 08/18/2023<br><br>Instrument: 2023176564	-	Date: 01/22/2024<br><br>Instrument: 2024177251	Date: 05/06/2024 Instrument: 2024177718
Solano	Date: 06/05/2023<br><br>Instrument: 202300023593	Date: 08/17/2023<br><br>Instrument: 202300035469	-	Date: 01/18/2024<br><br>Instrument: 202400002504	Date: 05/06/2024 Instrument: 202400018873

Sch. 1-15

	O	P	Q	R	S
County	Recording Date & Instrument Number<br><br>(Nineteenth Supplemental Indenture, dated as of March 30, 2023)	Recording Date & Instrument Number<br><br>(Twentieth Supplemental Indenture, dated as of June 5, 2023)	Recording Date & Instrument Number<br><br>(Certificate of Partial Release of Lien, dated as of December 15, 2023)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of December 29, 2023)	Recording Date & Instrument Number<br><br>(Twenty-Fourth Supplemental Indenture, dated as of February 28, 2024)
Sonoma	Date: 06/02/2023<br><br>Instrument: 2023024786	Date: 08/17/2023<br><br>Instrument: 2023038248	-	Date: 01/18/2024<br><br>Instrument: 2024002404	Date: 05/03/2024 Instrument: 2024019183
Stanislaus	Date: 06/05/2023<br><br>Instrument: 2023-0024714	Date: 08/17/2023<br><br>Instrument: 2023-0038394	-	Date: 01/23/2024<br><br>Instrument: 2024-0002726	Date: 05/06/2024 Instrument: 2024-0020385
Sutter	Date: 06/06/2023<br><br>Instrument: 2023-0004857	Date: 08/21/2023<br><br>Instrument: 2023-007403	-	Date: 01/23/2024<br><br>Instrument: 2024-0000602	Date: 05/06/2024 Instrument: 2024-0003684
Tehama	Date: 06/02/2023<br><br>Instrument: 2023005416	Date: 08/17/2023<br><br>Instrument: 2023008121	-	Date: 01/23/2024<br><br>Instrument: 2024000649	Date: 05/06/2024 Instrument: 2024003696
Trinity	Date: 06/05/2023<br><br>Instrument: 202301828	Date: 08/18/2023<br><br>Instrument: 202302638	-	Date: 01/22/2024<br><br>Instrument: 202400098	Date: 05/06/2024 Instrument: 202401374
Tulare	Date: 06/05/2023<br><br>Instrument: 2023-0025609	Date: 08/17/2023<br><br>Instrument: 2023-0037812	-	Date: 01/18/2024<br><br>Instrument: 2024-0002855	Date: 05/06/2024<br><br>Instrument: 2024-0019471
Tuolumne	Date: 06/05/2023<br><br>Instrument: 2023004401	Date: 08/17/2023<br><br>Instrument: 2023006880	-	Date: 01/18/2024<br><br>Instrument: 2024000467	Date: 05/06/2024 Instrument: 2024003548
Yolo	Date: 06/05/2023<br><br>Instrument: 2023-0008748	Date: 08/17/2023<br><br>Instrument: 2023-0013671	-	Date: 01/18/2024<br><br>Instrument: 2024-0000975	Date: 05/06/2024 Instrument: 2024-0007564
Yuba	Date: 06/05/2023<br><br>Instrument: 2023-005726	Date: 08/17/2023<br><br>Instrument: 2023-008437	-	Date: 01/18/2024<br><br>Instrument: 2024-000574	Date: 05/06/2024 Instrument: 2024-004650
	T	U	V	W
---	---	---	---	---
County	Recording Date & Instrument Number<br><br>(Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024)	Recording Date & Instrument Number<br><br>(Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025)	Recording Date & Instrument Number<br><br>(Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025)
Alameda	Date: 12/05/2024<br><br>Instrument: 2024149003	Date: 02/03/2025<br><br>Instrument: 2025015030	Date: 04/18/2025<br><br>Instrument: 2025051948	Date: 07/25/2025<br><br>Instrument: 2025093977
Alpine	Date: 12/10/2024<br><br>Instrument: 2024000585	Date: 02/03/2025<br><br>Instrument: 2025000037	Date: 04/21/2025<br><br>Instrument: 2025000132	Date: 07/29/2025<br><br>Instrument: 2025000268
Amador	Date: 12/10/2024<br><br>Instrument: 2024-0007136	Date: 02/04/2025<br><br>Instrument: 2025-0000606	Date: 04/21/2025<br><br>Instrument: 2025-0002481	Date: 07/30/2025<br><br>Instrument: 2025-0004540

Sch. 1-16

	T	U	V	W
County	Recording Date & Instrument Number<br><br>(Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024)	Recording Date & Instrument Number<br><br>(Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025)	Recording Date & Instrument Number<br><br>(Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025)
Butte	Date: 12/04/2024<br><br>Instrument: 2024-0031196	Date: 02/03/2025<br><br>Instrument: 2025-0002242	Date: 04/18/2025<br><br>Instrument: 2025-0009975	Date: 07/25/2025<br><br>Instrument: 2025-0019507
Calaveras	Date: 12/04/2024<br><br>Instrument: 2024-011910	Date: 01/31/2025<br><br>Instrument: 2025-001820	Date: 04/17/2025<br><br>Instrument: 2025-004124	Date: 07/24/2025<br><br>Instrument: 2025-007531
Colusa	Date: 12/09/2024<br><br>Instrument: 2024-0003117	Date: 02/04/2025<br><br>Instrument: 2025-0000265	Date: 04/21/2025<br><br>Instrument: 2025-0000917	Date: 07/28/2025<br><br>Instrument: 2025-0001754
Contra Costa	Date: 12/11/2024<br><br>Instrument: 2024-0132635	Date: 02/05/2025<br><br>Instrument: 2025-0011021	Date: 04/17/2025<br><br>Instrument: 2025-0037150	Date: 07/28/2025<br><br>Instrument: 2025-0075561
El Dorado	Date: 12/04/2024<br><br>Instrument: 2024-0035587	Date: 02/03/2025<br><br>Instrument: 2025-0002555	Date: 04/23/2025<br><br>Instrument: 2025-0010904	Date: 07/24/2025<br><br>Instrument: 2025-0021057
Fresno	Date: 12/04/2024<br><br>Instrument: 2024-0111858	Date: 01/31/2025<br><br>Instrument: 2025-0009442	Date: 04/23/2025<br><br>Instrument: 2025-0039390	Date: 08/12/2025<br><br>Instrument: 2025-0076411
Glenn	Date: 12/04/2024<br><br>Instrument: 2024-3660	Date: 02/05/2025<br><br>Instrument: 2025-0492	Date: 04/17/2025<br><br>Instrument: 2025-1348	Date: 07/24/2025<br><br>Instrument: 2025-2392
Humboldt	Date: 12/04/2024<br><br>Instrument: 2024-017868	Date: 02/03/2025<br><br>Instrument: 2025-001194	Date: 04/18/2025<br><br>Instrument: 2025-004716	Date: 07/25/2025<br><br>Instrument: 2025-009838
Kern	Date: 12/05/2024<br><br>Instrument: 224150310	Date: 02/05/2025<br><br>Instrument: 225012663	Date: 04/18/2025<br><br>Instrument: 225042665	Date: 07/25/2025<br><br>Instrument: 225084448
Kings	Date: 12/10/2024<br><br>Instrument: 2418367	Date: 02/03/2025<br><br>Instrument: 2501391	Date: 04/22/2025<br><br>Instrument: 2505124	Date: 07/25/2025<br><br>Instrument: 2510126
Lake	Date: 12/10/2024<br><br>Instrument: 2024013300	Date: 02/05/2025<br><br>Instrument: 2025001044	Date: 04/22/2025<br><br>Instrument: 2025003726	Date: 07/25/2025<br><br>Instrument: 2025007191
Lassen	Date: 12/09/2024<br><br>Instrument: 2024-03700	Date: 02/05/2025<br><br>Instrument: 2025-00333	Date: 04/21/2025<br><br>Instrument: 2025-01082	Date: 07/29/2025<br><br>Instrument: 2025-02332
Madera	Date: 12/04/2024<br><br>Instrument: 2024026286	Date: 01/31/2025<br><br>Instrument: 2025001978	Date: 04/17/2025<br><br>Instrument: 2025008040	Date: 07/25/2025<br><br>Instrument: 2025015341
Marin	Date: 12/05/2024<br><br>Instrument: 2024-0031964	Date: 02/03/2025<br><br>Instrument: 2025-0002781	Date: 04/24/2025<br><br>Instrument: 2025-0010981	Date: 07/25/2025<br><br>Instrument: 2025-0019602
Mariposa	Date: 12/10/2024<br><br>Instrument: 20243223	Date: 02/04/2025<br><br>Instrument: 20250295	Date: 04/21/2025<br><br>Instrument: 20250944	Date: 07/29/2025<br><br>Instrument: 20251869

Sch. 1-17

	T	U	V	W
County	Recording Date & Instrument Number<br><br>(Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024)	Recording Date & Instrument Number<br><br>(Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025)	Recording Date & Instrument Number<br><br>(Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025)
Mendocino	Date: 12/10/2024<br><br>Instrument: 2024-10519	Date: 02/20/2025<br><br>Instrument: 2025-01423	Date: 05/22/2025<br><br>Instrument: 2025-04275	Date: 07/29/2025<br><br>Instrument: 2025-06345
Merced	Date: 12/05/2024<br><br>Instrument: 2024028921	Date: 02/03/2025<br><br>Instrument: 2025004455	Date: 04/18/2025<br><br>Instrument: 2025010942	Date: 07/25/2025<br><br>Instrument: 2025020090
Modoc	Date: 12/04/2024<br><br>Instrument: 20240002970	Date: 02/03/2025<br><br>Instrument: 20250000161	Date: 04/18/2025<br><br>Instrument: 20250000650	Date: 07/25/2025<br><br>Instrument: 20250001640
Monterey	Date: 12/05/2024<br><br>Instrument: 2024047455	Date: 02/03/2025<br><br>Instrument: 2025003528	Date: 04/23/2025<br><br>Instrument: 2025012798	Date: 07/25/2025<br><br>Instrument: 2025024237
Napa	Date: 12/05/2024<br><br>Instrument: 2024-0017862	Date: 02/03/2025<br><br>Instrument: 2025-0001537	Date: 04/18/2025<br><br>Instrument: 2025-0005370	Date: 07/25/2025<br><br>Instrument: 2025-0010146
Nevada	Date: 12/05/2024<br><br>Instrument: 20240019105	Date: 02/03/2025<br><br>Instrument: 20250001376	Date: 04/23/2025<br><br>Instrument: 20250006277	Date: 07/25/2025<br><br>Instrument: 20250011455
Placer	Date: 12/05/2024<br><br>Instrument: 2024-0066158-00	Date: 02/03/2025<br><br>Instrument: 2025-0005581-00	Date: 04/18/2025<br><br>Instrument: 2025-0020991-00	Date: 07/25/2025<br><br>Instrument: 2025-0039696-00
Plumas	Date: 12/05/2024<br><br>Instrument: 2024-0005508	Date: 02/03/2025<br><br>Instrument: 2025-0000373	Date: 04/18/2025<br><br>Instrument: 2025-0001761	Date: 07/25/2025<br><br>Instrument: 2025-0003241
Sacramento	Date: 12/11/2024<br><br>Instrument: 202412110586	Date: 02/03/2025<br><br>Instrument: 202502030293	Date: 05/06/2025<br><br>Instrument: 202505060583	Date: 07/29/2025<br><br>Instrument: 202507290004
San Benito	Date: 12/05/2024<br><br>Instrument: 2024-0008146	Date: 02/03/2025<br><br>Instrument: 2025-0000628	Date: 04/17/2025<br><br>Instrument: 2025-0002335	Date: 07/28/2025<br><br>Instrument: 2025-0004621
San Bernardino	Date: 12/05/2024<br><br>Instrument: 2024-0289456	Date: 02/05/2025<br><br>Instrument: 2025-0024340	Date: 05/06/2025<br><br>Instrument: 2025-0102817	Date: 07/29/2025<br><br>Instrument: 2025-0178755
San Francisco	Date: 12/20/2024<br><br>Instrument: 2024098442	Date: 02/20/2025<br><br>Instrument: 2025013293	Date: 04/25/2025<br><br>Instrument: 2025031293	Date: 08/07/2025<br><br>Instrument: 2025065032
San Joaquin	Date: 12/05/2024<br><br>Instrument: 2024-106616	Date: 02/03/2025<br><br>Instrument: 2025-008214	Date: 04/18/2025<br><br>Instrument: 2025-031921	Date: 07/24/2025<br><br>Instrument: 2025-062046
San Luis Obispo	Date: 12/05/2024<br><br>Instrument: 2024035769	Date: 02/03/2025<br><br>Instrument: 2025002748	Date: 04/18/2025<br><br>Instrument: 2025010893	Date: 07/25/2025<br><br>Instrument: 2025021572

Sch. 1-18

	T	U	V	W
County	Recording Date & Instrument Number<br><br>(Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024)	Recording Date & Instrument Number<br><br>(Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025)	Recording Date & Instrument Number<br><br>(Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025)
San Mateo	Date: 12/05/2024<br><br>Instrument: 2024-065534	Date: 02/07/2025<br><br>Instrument: 2025-005530	Date: 04/18/2025<br><br>Instrument: 2025-018792	Date: 07/25/2025<br><br>Instrument: 2025-038099
Santa Barbara	Date: 12/05/2024<br><br>Instrument: 2024-0036296	Date: 02/04/2025<br><br>Instrument: 2025-0003129	Date: 04/18/2025<br><br>Instrument: 2025-0011457	Date: 07/28/2025<br><br>Instrument: 2025-0022631
Santa Clara	Date: 12/05/2024<br><br>Instrument: 25738920	Date: 02/03/2025<br><br>Instrument: 25761012	Date: 04/18/2025<br><br>Instrument: 25794001	Date: 07/25/2025<br><br>Instrument: 25844771
Santa Cruz	Date: 12/05/2024<br><br>Instrument: 2024-0024017	Date: 02/03/2025<br><br>Instrument: 2025-0001896	Date: 04/18/2025<br><br>Instrument: 2025-0007991	Date: 07/25/2025<br><br>Instrument: 2025-0015435
Shasta	Date: 12/05/2024<br><br>Instrument: 2024-0027656	Date: 02/03/2025<br><br>Instrument: 2025-0002123	Date: 04/18/2025<br><br>Instrument: 2025-0007836	Date: 07/25/2025<br><br>Instrument: 2025-0015815
Sierra	Date: 12/10/2024<br><br>Instrument: 2024178542	Date: 02/03/2025<br><br>Instrument: 2025178708	Date: 04/21/2025<br><br>Instrument: 2025178844	Date: 07/28/2025<br><br>Instrument: 2025179099
Solano	Date: 12/05/2024<br><br>Instrument: 202400055983	Date: 02/03/2025<br><br>Instrument: 202500004350	Date: 04/18/2025<br><br>Instrument: 202500017246	Date: 07/25/2025<br><br>Instrument: 202500033557
Sonoma	Date: 12/05/2024<br><br>Instrument: 2024059924	Date: 02/03/2025<br><br>Instrument: 2025004713	Date: 04/18/2025<br><br>Instrument: 2025017233	Date: 07/24/2025<br><br>Instrument: 2025034644
Stanislaus	Date: 12/05/2024<br><br>Instrument: 2024-0058643	Date: 02/03/2025<br><br>Instrument: 2025-0004338	Date: 04/18/2025<br><br>Instrument: 2025-0018805	Date: 07/25/2025<br><br>Instrument: 2025-0036350
Sutter	Date: 12/05/2024<br><br>Instrument: 2024-0010667	Date: 02/07/2025<br><br>Instrument: 2025-0001093	Date: 05/07/2025<br><br>Instrument: 2025-0003923	Date: 07/29/2025<br><br>Instrument: 2025-0006533
Tehama	Date: 12/05/2024<br><br>Instrument: 2024011389	Date: 02/03/2025<br><br>Instrument: 2025000816	Date: 04/18/2025<br><br>Instrument: 2025002909	Date: 07/25/2025<br><br>Instrument: 2025006856
Trinity	Date: 12/10/2024<br><br>Instrument: 202403604	Date: 02/04/2025<br><br>Instrument: 202500306	Date: 04/21/2025<br><br>Instrument: 202501045	Date: 07/28/2025<br><br>Instrument: 202501834
Tulare	Date: 12/05/2024<br><br>Instrument: 2024-0060928	Date: 02/03/2025<br><br>Instrument: 2025-0004636	Date: 04/18/2025<br><br>Instrument: 2025-0017432	Date: 07/25/2025<br><br>Instrument: 2025-0035664
Tuolumne	Date: 12/05/2024<br><br>Instrument: 2024-010857	Date: 02/03/2025<br><br>Instrument: 2025-000974	Date: 04/18/2025<br><br>Instrument: 2025-003433	Date: 07/25/2025<br><br>Instrument: 2025-006392

Sch. 1-19

	T	U	V	W
County	Recording Date & Instrument Number<br><br>(Twenty-Fifth Supplemental Indenture, dated as of September 5, 2024)	Recording Date & Instrument Number<br><br>(Twenty-Sixth Supplemental Indenture, dated as of January 17, 2025)	Recording Date & Instrument Number<br><br>(Memorandum of Supplemental First Mortgage Indentures, dated as of March 4, 2025)	Recording Date & Instrument Number<br><br>(Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025)
Yolo	Date: 12/05/2024<br><br>Instrument: 2024-0021928	Date: 02/03/2025<br><br>Instrument: 2025-0001620	Date: 04/18/2025<br><br>Instrument: 2025-0006155	Date: 07/25/2025<br><br>Instrument: 2025-0012200
Yuba	Date: 12/05/2024<br><br>Instrument: 2024-013308	Date: 02/03/2025<br><br>Instrument: 2025-001219	Date: 04/18/2025<br><br>Instrument: 2025-004197	Date: 07/25/2025<br><br>Instrument: 2025-008209

Sch. 1-20

Document

EXHIBIT 10.6.5

AMENDMENT NO. 5 TO CREDIT AGREEMENT

This AMENDMENT NO. 5, dated as of December 19, 2025 (this “Amendment”), is entered into by and among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), each lender party hereto (the “Lenders”) and BANK OF AMERICA, N.A., as administrative agent (in such capacity, the “Administrative Agent”).

RECITALS:

WHEREAS, reference is hereby made to the Credit Agreement, dated as of April 20, 2022, among the Borrower, the Lenders and the Administrative Agent (as amended by that certain Amendment No. 1 to Credit Agreement dated as of September 23, 2022, that certain Amendment No. 2 to Credit Agreement dated as of April 18, 2023, that certain Amendment No. 3 to Credit Agreement dated as of April 16, 2024 and that certain Amendment No. 4 to Credit Agreement dated as of April 11, 2025, the “Credit Agreement”; capitalized terms used (including in the preamble and recitals hereto) but not defined herein shall have the meanings assigned to such terms in the Credit Agreement); and

WHEREAS, the Borrower has requested, and the Lenders have agreed, to amend the Credit Agreement, on the terms and subject to the conditions set forth in this Amendment, including to (i) make Loans to the Borrower in a principal amount equal to $75,000,000 (the “Amendment No. 5 Loans”) on the Amendment No. 5 Effective Date (as defined below) and (ii) extend the 364-Day Tranche Maturity Date to December 18, 2026.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration (the receipt and sufficiency of which is hereby acknowledged), the parties hereto hereby agree as follows:

A.    Amendment No. 5 Loans. On the Amendment No. 5 Effective Date, the Lender party hereto agrees to make Amendment No. 5 Loans to the Borrower in a principal amount equal to its Commitment as set forth on Schedule I hereto (the “Amendment No. 5 Commitments”), with such Amendment No. 5 Loans having terms identical to the 364-Day Tranche Loans outstanding under the Credit Agreement immediately prior to the Amendment No. 5 Effective Date (the “Existing Loans”). From and after the Amendment No. 5 Effective Date, the Amendment No. 5 Loans shall increase the outstanding principal amount of the Existing Loans.

B.    Amendment to the Credit Agreement. As of the Amendment No. 5 Effective Date, (a) the Credit Agreement is hereby amended to (x) delete the stricken text (indicated textually in the same manner as the following example: stricken text) and (y) add the double-underlined text (indicated textually in the same manner as the following example: double-underlined text) as set forth in Annex A to this Amendment and (b) Schedule 1.1 to the Credit Agreement is amended and replaced in its entirety with Schedule 1.1 as set forth in Annex B to this Amendment.

C.    Conditions Precedent. This Amendment shall become effective as of the date first above written when each of the following conditions precedent shall have been satisfied (the “Amendment No. 5 Effective Date”):

1.    Executed Counterparts. The Administrative Agent shall have received a counterpart to this Amendment duly executed by the Borrower and all of the Lenders;

2.    Organizational Documents; Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated as of the Amendment No. 5 Effective Date (with a recent short-form good standing certificate of the Borrower), similar to the one delivered pursuant to Section 5.1(f)(i) of the Credit Agreement, with appropriate insertions and attachments and (ii) a certificate of a Responsible Officer, dated the Amendment No. 5 Effective Date, confirming the satisfaction of the conditions precedent set forth in clauses (3) and (4) below;

3.    Representations and Warranties. The representations and warranties of the Borrower contained in Section 4 of the Credit Agreement (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13) shall be true and correct in all material respects immediately prior to and immediately after giving effect to this Amendment; provided that each of such representations and warranties that contains a materiality qualification shall be true and correct on and as of the Amendment No. 5 Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date);

4.    No Default. No Default or Event of Default shall have occurred and be continuing immediately prior to, and immediately after giving effect to, the Amendment No. 5 Effective Date or would result from the funding of the Amendment No. 5 Loans on the Amendment No. 5 Effective Date;

5.    Legal Opinion. The Administrative Agent shall have received the legal opinion of Hunton Andrews Kurth LLP, counsel to the Borrower, in a form reasonably satisfactory to the Administrative Agent;

6.    Know Your Customer Information. The Administrative Agent shall have received, at least five (5) Business Days prior to the Amendment No. 5 Effective Date, all documentation and other information with respect to the Borrower reasonably requested by it, which documentation is required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the USA PATRIOT Act;

7.    Fees and Expenses. On or prior to the Amendment No. 5 Effective Date, the Borrower shall have paid all reasonable out-of-pocket costs and expenses of the Administrative Agent required to be paid or reimbursed by the Borrower in connection with the preparation, negotiation, execution and delivery of this Amendment and related documentation (including, in each case, without limitation, the reasonable fees and disbursements of counsel for the Administrative Agent with respect thereto); and

8.    Bond Documents. The Borrower shall have caused to be issued to the Administrative Agent a new First Mortgage Bond (the “New FMB”) in the amount of $600,000,000, such that the maturity date of such Senior Bond will be December 18, 2026. Upon receipt of the New FMB, the Administrative Agent shall return to the Borrower the First Mortgage Bond of the Forty-Ninth Series in the amount of $525,000,000 issued on the Amendment No. 4 Effective Date (as defined in the Credit Agreement). In addition, the Administrative Agent shall have received:

(i)    the New FMB, duly issued and authenticated under the FMB Indenture and in a form reasonably satisfactory to the Administrative Agent;

(ii)    a certificate of a duly authorized officer of the Indenture Trustee certifying that the New FMB has been authenticated and is outstanding under the FMB Indenture;

(iii)    copies of all other documents delivered to the Indenture Trustee by or on behalf of the Borrower on or prior to the Amendment No. 5 Effective Date in connection with the issuance of the New FMB (including, as it relates to the new maturity date and face amount of the New FMB of $600,000,000.00, all other documents required under the procedures identified in Sections 601 and 602 of the Fifteenth Supplemental Indenture); and

(iv)    copies of all title reports and commitments, if any, as of the Amendment No. 5 Effective Date with respect to the Mortgaged Property consisting of real property as to which Liens in favor of the Indenture Trustee, for the benefit of the holders of the New FMB, has been granted.

D.    Other Terms.

1.    Reference to the Effect on the Loan Documents.

(i)    As of the Amendment No. 5 Effective Date, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, and each reference in the other Loan Documents to the “Credit Agreement” (including, without limitation, by means of words like “thereunder,” “thereof” and words of like import), shall mean and be a reference to the Credit Agreement as amended hereby, and this Amendment and the Credit Agreement shall be read together and construed as a single instrument. The Amendment No. 5 Loans shall be part of the same Tranche as the Existing Loans and shall constitute “364-Day Tranche Loans” and “Loans” for all purposes under the Credit Agreement, as amended hereby.

(ii)    Except as expressly amended hereby or specifically waived above, all of the terms and provisions of the Credit Agreement and all other Loan Documents are and shall remain in full force and effect and are hereby ratified and confirmed.

(iii)    The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders, the Borrower, or the Administrative Agent under any of the Loan Documents, nor constitute a waiver or amendment of any other provision of any of the Loan Documents or for any purpose except as expressly set forth herein.

(iv)    This Amendment is a Loan Document.

(v)    The Borrower hereby requests a 1-month Term SOFR Rate Interest Period with respect to the Amendment No. 5 Loans in the aggregate principal amount of $75,000,000 which will begin on the Amendment No. 5 Effective Date and end on the last day of the then current interest period of the Existing Loans. The parties hereto agree that any notice requirement set forth in Section 2.2 of the Credit Agreement has been satisfied.

2.    Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page of this Amendment that is an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with

the intent to sign, authenticate or accept such contract or record (each, an “Electronic Signature”) transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Amendment shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be.

3.    Ratification. This Amendment shall be effective pursuant to Section 10.1 of the Credit Agreement (and approved and ratified by all Lenders and the Administrative Agent for all purposes under the Loan Documents).

4.    Governing Law. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

5.    Section Titles. The section titles contained in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto, except when used to reference a section.

6.    Notices. All communications and notices hereunder shall be given as provided in the Credit Agreement.

7.    Severability. The fact that any term or provision of this Amendment is held invalid, illegal or unenforceable as to any person in any situation in any jurisdiction shall not affect the validity, enforceability or legality of the remaining terms or provisions hereof or the validity, enforceability or legality of such offending term or provision in any other situation or jurisdiction or as applied to any person.

8.    Successors. The terms of this Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.

9.    Jurisdiction; Waiver of Jury Trial. The jurisdiction and waiver of right to trial by jury provisions in Section 10.12 and Section 10.15, respectively, of the Credit Agreement are incorporated herein by reference mutatis mutandis.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

IN WITNESS WHEREOF, each of the undersigned has caused its duly authorized officer to execute and deliver this Amendment as of the date first set forth above.

PACIFIC GAS AND ELECTRIC COMPANY, as the Borrower

By:     /s/ Margaret K. Becker

Name:    Margaret K. Becker

Title:    Vice President, Internal Audit and Treasurer

Signature Page to Amendment No. 5 Pacific Gas and Electric Company

BANK OF AMERICA, N.A. as Administrative Agent

By:     /s/ Jacqueline G. Margetis

Name:    Jacqueline G. Margetis

Title:    Director

Signature Page to Amendment No. 5 Pacific Gas and Electric Company

BANK OF AMERICA, N.A. as Lender

By:     /s/ Jacqueline G. Margetis

Name:    Jacqueline G. Margetis

Title:    Director

Signature Page to Amendment No. 5 Pacific Gas and Electric Company

Schedule I

Amendment No. 5 Commitments

364-Day Tranche Lender	Amendment No. 5 Commitment
Bank of America, N.A.	$75,000,000.00
Total:	$75,000,000.00

Signature Page to Amendment No. 5 Pacific Gas and Electric Company

Annex A

Amended Credit Agreement

Execution Version

$525,000,000600,000,000

TERM LOAN CREDIT AGREEMENT

among

PACIFIC GAS AND ELECTRIC COMPANY, as Borrower,

the Lenders from Time to Time Parties Hereto,

and

BANK OF AMERICA, N.A.
as Administrative Agent,

Dated as of April 20, 2022

[as amended by Amendment No. 1 dated as of September 23, 2022, Amendment No. 2 dated as of April 18, 2023, Amendment No. 3 dated as of April 16, 2024 and, Amendment No. 4 dated as of April 11, 2025] and Amendment No. 5 dated as of December 19, 2025

TABLE OF CONTENTS

Page

Section 1.    DEFINITIONS    1

1.1    Defined Terms    1

1.2    Other Definitional Provisions and Interpretative Provisions    27

1.3    Divisions    29

1.4    Interest Rates; Benchmark Notification    29

Section 2.    AMOUNT AND TERMS OF THE TERM LOANS    29

2.1    Loans    29

2.2    Procedures for Borrowing    30

2.3    [Reserved.]    30

2.4    [Reserved]    30

2.5    [Reserved]    30

2.6    Fees, Etc    30

2.7    Termination of Commitments; Extension of Maturity Date    31

2.8    Optional Prepayments    31

2.9    Conversion and Continuation Options    31

2.10    Limitations on Term Benchmark Loans    32

2.11    Interest Rates and Payment Dates    32

2.12    Computation of Interest and Fees    33

2.13    Inability to Determine Interest Rate    33

2.14    Pro Rata Treatment and Payments; Notes    35

2.15    Change of Law    37

2.16    Taxes    38

2.17    Indemnity    43

2.18    Change of Lending Office    43

2.19    Replacement of Lenders    43

2.20    Defaulting Lenders    44

2.21    [Reserved]    45

Section 3.    [RESERVED].    45

Section 4.    REPRESENTATIONS AND WARRANTIES    45

4.1    Financial Condition    45

4.2    No Change    45

4.3    Existence; Compliance with Law    45

4.4    Power; Authorization; Enforceable Obligations    46

4.5    No Legal Bar    46

4.6    Litigation    46

4.7    No Default    47

4.8    Taxes    47

4.9    Federal Regulations    47

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4.10    ERISA    47

4.11    Investment Company Act; Other Regulations    48

4.12    Use of Proceeds    48

4.13    Environmental Matters    48

4.14    Regulatory Matters    48

4.15    Sanctions; Anti-Corruption    47

4.16    Affected Financial Institutions    49

4.17    Solvency    49

4.18    Disclosure    49

4.19    Status of Obligations    49

4.20    Ownership of Property    50

4.21    Covered Entity    50

4.22    Outbound Investment Rules    50

Section 5.    CONDITIONS PRECEDENT    50

5.1    Conditions to the Effective Date    50

Section 6.    AFFIRMATIVE COVENANTS    52

6.1    Financial Statements    52

6.2    Certificates; Other Information    52

6.3    Payment of Taxes    53

6.4    Maintenance of Existence; Compliance    53

6.5    Maintenance of Property; Insurance    54

6.6    Inspection of Property; Books and Records; Discussions    54

6.7    Notices    54

6.8    Maintenance of Licenses, etc    55

6.9    Further Assurances    55

6.10    Use of Proceeds    55

Section 7.    NEGATIVE COVENANTS    55

7.1    [Reserved]    55

7.2    Consolidated Capitalization Ratio    57

7.3    Liens    57

7.4    Fundamental Changes    57

7.5    Sale and Lease Back Transactions    58

7.6    Swap Agreements    58

7.7    Amendments to FMB Indenture    58

7.8    Outbound Investment Rules    58

Section 8.    EVENTS OF DEFAULT    59

Section 9.    THE AGENTS    61

9.1    Appointment and Authority    61

9.2    Delegation of Duties    62

9.3    Exculpatory Provisions    62

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9.4    Reliance by Administrative Agent    63

9.5    Notice of Default    63

9.6    Non-Reliance on Agents and Other Lenders    64

9.7    Indemnification    64

9.8    Agent in Its Individual Capacity    64

9.9    Successor Agents    65

9.10    Reserved    66

9.11    Administrative Agent May File Proofs of Claim    66

9.12    Certain ERISA Matters    67

9.13    Erroneous Payment    68

Section 10.    MISCELLANEOUS    70

10.1    Amendments and Waivers    70

10.2    Notices    72

10.3    No Waiver; Cumulative Remedies    74

10.4    Survival of Representations and Warranties    74

10.5    Payment of Expenses and Taxes    74

10.6    Successors and Assigns; Participations and Assignments    76

10.7    Adjustments; Set off    80

10.8    Counterparts; Electronic Execution; Binding Effect    81

10.9    Severability    81

10.10    Integration    82

10.11    GOVERNING LAW    82

10.12    Submission To Jurisdiction; Waivers    82

10.13    Acknowledgments    83

10.14    Confidentiality    83

10.15    WAIVERS OF JURY TRIAL    84

10.16    USA Patriot Act; Beneficial Ownership Regulation    84

10.17    Judicial Reference    84

10.18    No Advisory or Fiduciary Responsibility    84

10.19    Acknowledgement Regarding Any Supported QFCs    85

10.20    Acknowledgement and Consent to Bail-In of Affected Financial Institutions    86

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SCHEDULES:

1.1    Commitments

7.5    Sale and Lease Back Transactions

EXHIBITS:

A    [Reserved]

B    [Reserved]

C    Form of Compliance Certificate

D-1    Form of Secretary’s Certificate

D-2    Form of Officer’s Certificate

E    Form of Assignment and Assumption

F    [Reserved]

G    Forms of U.S. Tax Compliance Certificates

H    Form of Note

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This TERM LOAN CREDIT AGREEMENT (this “Agreement”), dated as of April 20, 2022, among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), the banks and other financial institutions or entities from time to time parties to this Agreement (the “Lenders”) and BANK OF AMERICA, N.A., as administrative agent (in such capacity, together with any permitted successor thereto, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, the Borrower has requested that the Lenders provide the term loans set forth herein and the Lenders are willing to make available to the Borrower such term loans upon the terms and subject to the conditions set forth herein.

NOW, THEREFORE, IT IS AGREED AS FOLLOWS:

SECTION 1.    DEFINITIONS

1.1    Defined Terms. As used in this Agreement, the terms listed in this Section 1 shall have the respective meanings set forth in this Section 1.

“364-Day Tranche Commitment”: as to each 364-Day Tranche Lender, its obligation to make 364-Day Tranche Loans to the Borrower on the Amendment No. 3 Effective Date pursuant to Section 2.1(a), in an aggregate principal amount equal to the amount set forth opposite such 364-Day Tranche Lender’s name on Schedule 1.1, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Amendment No. 3 Effective Date, the aggregate amount of the 364-Day Tranche Commitments for all 364-Day Tranche Lenders iswas $525,000,000.

“364-Day Tranche Lender”: a Lender with a 364-Day Tranche Commitment or Amendment No. 5 Commitment or holding a 364-Day Tranche Loan.

“364-Day Tranche Loans”: as defined in Section 2.1(a). The aggregate principal amount of the 364-Day Tranche Loans outstanding on the Amendment No. 5 Effective Date is $600,000,000.

“364-Day Tranche Maturity Date”: April 10December 18, 2026 (or to the extent applicable to any Extending Lender, such later date as determined pursuant to Section 2.7).

“ABR”: for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the NYFRB Rate in effect on such day plus 1/2 of 1% and (c) the Adjusted Term SOFR Rate for a one month Interest Period as published two U.S. Government Securities Business Days prior to such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1%; provided that for the purpose of this definition, the Adjusted Term SOFR Rate for any day shall be based on the Term SOFR Reference Rate at approximately 5:00 a.m. Chicago time on such day (or any

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amended publication time for the Term SOFR Reference Rate, as specified by the CME Term SOFR Administrator in the Term SOFR Reference Rate methodology). Any change in the ABR due to a change in the Prime Rate, the NYFRB Rate or the Adjusted Term SOFR Rate shall be effective from and including the effective date of such change in the Prime Rate, the NYFRB Rate or the Adjusted Term SOFR Rate, respectively. If ABR is being used as an alternate rate of interest pursuant to Section 2.13 (for the avoidance of doubt, only until any amendment has become effective pursuant to Section 2.13(b)), then ABR shall be the greater of clauses (a) and (b) above and shall be determined without reference to clause (c) above. If the ABR as determined pursuant to the foregoing would be less than 1.00%, such rate shall be deemed to be 1.00% for purposes of this Agreement.

“ABR Loans”: Loans the rate of interest applicable to which is based upon the ABR.

“Adjusted Daily Simple SOFR”: an interest rate per annum equal to (a) Daily Simple SOFR, plus (b) 0.10%; provided that if Adjusted Daily Simple SOFR as so determined would be less than the Floor, such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Adjusted Term SOFR Rate”: for any Interest Period, an interest rate per annum equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10%; provided that if the Adjusted Term SOFR Rate as so determined would be less than the Floor, such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Administrative Agent”: as defined in the preamble hereto.

“Affected Financial Institution”: (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate”: with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Agent Parties”: as defined in Section 10.2(d)(ii).

“Agents”: the Administrative Agent.

“Agreement”: as defined in the preamble hereto.

“Amendment No. 3”: that certain Amendment No. 3 to Credit Agreement, dated as of April 16, 2024, by and among the Borrower, each Lender party thereto and the Administrative Agent.

“Amendment No. 3 Effective Date”: as defined in Section B of Amendment No. 3, which date is April 16, 2024.

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“Amendment No. 3 Loans”: as defined in Section 2.1(a).

“Amendment No. 5”: that certain Amendment No. 5 to Credit Agreement, dated as of December 19, 2025, by and among the Borrower, each Lender party thereto and the Administrative Agent.

“Amendment No. 5 Commitment”: as to each 364-Day Tranche Lender, its obligation to make Amendment No. 5 Loans to the Borrower on the Amendment No. 5 Effective Date pursuant to Section 2.1(b), in an aggregate principal amount equal to the amount set forth opposite such 364-Day Tranche Lender’s name on Schedule I to Amendment No. 5, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Amendment No. 5 Effective Date, the aggregate amount of the Amendment No. 5 Commitments for all 364-Day Tranche Lenders was $75,000,000.

“Amendment No. 5 Effective Date”: as defined in Section C of Amendment No. 5, which date is December 19, 2025.

“Amendment No. 5 Loans”: as defined in Section 2.1(b).

“Anti-Corruption Laws”: as defined in Section 4.15.

“Applicable Margin”: for any day, with respect to 364-Day Tranche Loans that are (i) ABR Loans, 0.3750.25% per annum and (ii) Term Benchmark Loans, 1.3751.25% per annum.

“Approved Fund”: with respect to any Lender, any Person (other than a natural person) that is engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business that is administered or managed by (a) such Lender, (b) an Affiliate of such Lender or (c) an entity or an Affiliate of any entity that administers or manages such Lender.

“Arranger”: Bank of America, N.A., an affiliate of BofA Securities, Inc., in its capacity as sole lead arranger and sole bookrunner.

“A/R Securitization Assets”: (i) any accounts receivable, notes receivable, rights to future accounts receivable, notes receivable or residuals or other similar rights to payments due or any other rights to payment or related assets in respect of the provision of gas and electric service to consumers or otherwise (whether then existing or arising in the future) of the Borrower or any of its Subsidiaries and the proceeds thereof and (ii) all collateral securing such receivable or asset, all contracts and contract rights, guarantees or other obligations in respect of such receivable or asset, lockbox accounts and records with respect to such receivables or asset and any other assets customarily transferred (or in respect of which security interests are customarily granted) together with receivables or assets in connection with a securitization transaction involving such assets.

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“A/R Securitization Subsidiary”: PG&E AR Facility, LLC and any other Subsidiary formed and operating solely for the purpose of entering into A/R Securitization Transactions and engaging in activities ancillary thereto.

“A/R Securitization Transaction”: any financing transaction or series of financing transactions entered into by the Borrower or any Subsidiary of the Borrower pursuant to which the Borrower may sell, convey or otherwise transfer to any Person (including, without limitation, an A/R Securitization Subsidiary), or may grant a security interest in any A/R Securitization Assets and that are (other than to the extent of the Standard A/R Securitization Obligations) non-recourse to the Borrower or any of its Subsidiaries (other than an A/R Securitization Subsidiary).

“Assignee”: as defined in Section 10.6(b).

“Assignment and Assumption”: an Assignment and Assumption, substantially in the form of Exhibit E.

“Available Tenor”: as of any date of determination and with respect to the then-current Benchmark, as applicable, any tenor for such Benchmark (or component thereof) or payment period for interest calculated with reference to such Benchmark (or component thereof), as applicable, that is or may be used for determining the length of an Interest Period for any term rate or otherwise, for determining any frequency of making payments of interest calculated pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant to Section 2.13(e).

“Bail-In Action”: the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation”: (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Benchmark”: initially, with respect to any Term Benchmark Loan, the Term SOFR Rate; provided that if a Benchmark Transition Event, and the related Benchmark Replacement Date, have occurred with respect to Daily Simple SOFR or the Term SOFR Rate, as applicable, or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to Section 2.13(b).

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“Benchmark Replacement”: for any Available Tenor, the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1)    Adjusted Daily Simple SOFR; and

(2)    the sum of: (a) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower as the replacement for the then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a benchmark rate as a replacement for the then-current Benchmark for dollar-denominated syndicated credit facilities at such time in the United States and (b) the related Benchmark Replacement Adjustment;

If the Benchmark Replacement as determined pursuant to clause (1) or (2) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Loan Documents.

“Benchmark Replacement Adjustment”: with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement, the spread adjustment, or method for calculating or determining such spread adjustment (which may be a positive or negative value or zero), that has been selected by the Administrative Agent and the Borrower for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body as of the applicable Benchmark Replacement Date and/or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for dollar-denominated syndicated credit facilities at such time.

“Benchmark Replacement Conforming Changes”: with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “ABR,” the definition of “Business Day,” the definition of “U.S. Government Securities Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, length of lookback periods, the applicability of breakage provisions, and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines

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that no market practice for the administration of such Benchmark exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Loan Documents).

“Benchmark Replacement Date”: with respect to any Benchmark, the earlier to occur of the following events with respect to such then-current Benchmark:

(1)    in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof); or

(2)    in the case of clause (3) of the definition of “Benchmark Transition Event,” the first date on which such Benchmark (or the published component used in the calculation thereof) has been determined and announced by the regulatory supervisor for the administrator of such Benchmark (or such component thereof) to be no longer representative; provided, that such non-representativeness will be determined by reference to the most recent statement or publication referenced in such clause (3) and even if any Available Tenor of such Benchmark (or such component thereof) continues to be provided on such date.

For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Transition Event”: with respect to any Benchmark, the occurrence of one or more of the following events with respect to such then-current Benchmark:

(1) a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(2) a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Federal Reserve Board, the NYFRB, the CME Term SOFR Administrator, an insolvency official with jurisdiction over the administrator for such

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Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), in each case, which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such

Benchmark (or such component thereof) permanently or indefinitely; provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(3) a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer, or as of a specified future date will no longer be, representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period”: with respect to any Benchmark, the period (if any) (x) beginning at the time that a Benchmark Replacement Date has occurred if, at such time, no Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any other Loan Document in accordance with Section 2.13 and (y) ending at the time that a Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any other Loan Document in accordance with Section 2.13.

“Beneficial Owner”: as defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Sections 13(d) and 14(d) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition.  The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Beneficial Ownership Certification”: a certification regarding beneficial ownership or control as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation”: 31 C.F.R. § 1010.230.

“Benefit Plan”: any of (a) an “employee benefit plan” (as defined in ERISA) that is subject to Title I of ERISA, (b) a “plan” as defined in and subject to Section 4975 of

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the Code or (c) any Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“Benefitted Lender”: as defined in Section 10.7(a).

“BHC Act Affiliate”: an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)).

“Bond Delivery Agreement”: that certain Bond Delivery Agreement, dated as of the Effective Date, between the Borrower and the Administrative Agent.

“Bond Documents”: collectively, the FMB Indenture, the Supplemental Indenture, the Senior Bond and the Bond Delivery Agreement.

“Borrower”: as defined in the preamble hereto.

“Business Day”: a day (other than a Saturday or a Sunday) on which banks are open for business in New York City or Chicago; provided that, in relation to RFR Loans and any interest rate settings, fundings, disbursements, settlements or payments of any such RFR Loan, or any other dealings of such RFR Loan, any such day that is only a U.S. Government Securities Business Day.

“Capital Lease Obligations”: as to any Person, the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on the balance sheet of such Person under GAAP and, for the purposes of this Agreement, the amount of such obligations at any time shall be the capitalized amount thereof at such time determined in accordance with GAAP, subject to Section 1.2(f).

“Capital Stock”: any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent ownership interests in a Person (other than a corporation) and any and all warrants, rights or options to purchase any of the foregoing.

“Change of Control”: the occurrence of one of the following:

(i)    (A) PCG shall at any time not be the Beneficial Owner of 100% of the common stock of the Borrower or (B) PCG shall at any time not be the Beneficial Owner of at least 70% of the voting Capital Stock of the Borrower; or

(ii)    any person or group (within the meaning of the Exchange Act and the rules of the SEC thereunder as of the Effective Date) shall become the Beneficial Owner of shares representing more than 35% of the voting power of the Capital Stock of PCG; or

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(iii)    at any point during any period of 24 consecutive months, commencing after the Effective Date, individuals who at the beginning of such 24-month period were directors of PCG, together with any directors whose election or nomination for election to the board of directors of PCG (whether by the board of directors of PCG or any shareholder of PCG) was approved by a majority of the directors who either were directors of PCG at the beginning of such 24-month period or whose election or nomination for election was so approved, cease to constitute a majority of the board of directors of PCG; or

(iv)    there shall have been a transfer of the license and/or operating assets constituting more than 10% of the Net Tangible Assets of the Borrower to the State of California, to any other Governmental Authority or to a third party at the direction of the State of California, the CPUC or any similar Governmental Authority.

“Change of Law”: the occurrence, after the Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation, statute, treaty, policy, guideline or directive by any Governmental Authority, (b) any change in any law, rule, regulation, statute, treaty, policy, guideline or directive or in the application, interpretation, promulgation, implementation, administration or enforcement thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change of Law”, regardless of the date enacted, adopted or issued.

“CME Term SOFR Administrator”: CME Group Benchmark Administration Limited as administrator of the term Secured Overnight Financing Rate (SOFR) (or a successor administrator; provided that, in the event there are multiple successor administrators, the successor administrator hereunder shall be selected by the Administrative Agent and the Borrower).

“Code”: the Internal Revenue Code of 1986, as amended from time to time.

“Commitment”: as to any Lender, its 364-Day Tranche Commitment or its Amendment No. 5 Commitment.

“Commonly Controlled Entity”: an entity, whether or not incorporated, that is under common control with the Borrower within the meaning of Section 4001 of ERISA or is part of a group that includes the Borrower and that is treated as a single employer under Section 414 of the Code.

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“Communications”: as defined in Section 10.2(d)(ii).

“Compliance Certificate”: a certificate duly executed by a Responsible Officer substantially in the form of Exhibit C.

“Conduit Lender”: any special purpose corporation organized and administered by any Lender for the purpose of making Loans otherwise required to be made by such Lender and designated by such Lender in a written instrument; provided, that the designation by any Lender of a Conduit Lender shall not relieve the designating Lender of any of its obligations to fund a Loan under this Agreement if, for any reason, its Conduit Lender fails to fund any such Loan, and the designating Lender (and not the Conduit Lender) shall have the sole right and responsibility to deliver all consents and waivers required or requested under this Agreement with respect to its Conduit Lender, and provided, further, that no Conduit Lender shall (a) be entitled to receive any greater amount pursuant to Sections 2.14, 2.16, 2.17 or 10.5 than the designating Lender would have been entitled to receive in respect of the extensions of credit made by such Conduit Lender or (b) be deemed to have any Commitment.

“Connection Income Taxes”: Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Capitalization”: on any date of determination, the sum of (a) Consolidated Total Debt on such date, plus without duplication, (b) (i) the amounts set forth opposite the captions “common shareholders’ equity” (or any similar caption) and “preferred stock” (or any similar caption) on the consolidated balance sheet, prepared in accordance with GAAP, of the Borrower and its Subsidiaries as of such date, and (ii) the outstanding principal amount of any junior subordinated deferrable interest debentures or other similar securities issued by the Borrower or any of its Subsidiaries after the Effective Date.

“Consolidated Capitalization Ratio”: on any date of determination, the ratio of (a) Consolidated Total Debt to (b) Consolidated Capitalization.

“Consolidated Total Debt”: at any date, the aggregate principal amount of all obligations of the Borrower and its Significant Subsidiaries at such date that in accordance with GAAP would be classified as debt on a consolidated balance sheet of the Borrower, and without duplication all Guarantee Obligations of the Borrower and its Significant Subsidiaries at such date in respect of obligations of any other Person that in accordance with GAAP would be classified as debt on a consolidated balance sheet of such Person; provided that, the determination of “Consolidated Total Debt” shall exclude, without duplication, (a) the Securitized Bonds and any Indebtedness under any A/R Securitization Transaction, (b) Indebtedness of the Borrower and its Significant Subsidiaries in an amount equal to the amount of cash held as cash collateral for any fully cash collateralized letter of credit issued for the account of the Borrower or any Significant Subsidiary, (c) imputed Indebtedness of the Borrower or any Significant

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Subsidiary incurred in connection with power purchase and fuel agreements, (d) any junior subordinated deferrable interest debenture or other similar securities issued by the Borrower and (e) as of any date of determination, the amount of any securities included within the caption “preferred stock” (or any similar caption) on a consolidated balance sheet, prepared in accordance with GAAP, of the Borrower as of such date.

“Contractual Obligation”: as to any Person, any provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.

“Control”: the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

“Corresponding Tenor”: with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding business day adjustment) as such Available Tenor.

“Covered Entity”: any of the following:

(i)    a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b);

(ii)    a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or

(iii)    a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Covered Party”: as defined in Section 10.19.

“CPUC”: the California Public Utilities Commission or its successor.

“Daily Simple SOFR”: for any day (a “SOFR Rate Day”), a rate per annum equal to SOFR for the day that is five (5) U.S. Government Securities Business Day prior to (i) if such SOFR Rate Day is a U.S. Government Securities Business Day, such SOFR Rate Day or (ii) if such SOFR Rate Day is not a U.S. Government Securities Business Day, the U.S. Government Securities Business Day immediately preceding such SOFR Rate Day, in each case, as such SOFR is published by the SOFR Administrator on the SOFR Administrator’s Website. Any change in Daily Simple SOFR due to a change in SOFR shall be effective from and including the effective date of such change in SOFR without notice to the Borrower.

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“Debtor Relief Laws”: the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect.

“Default”: any of the events specified in Section 8, whether or not any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Default Right”: the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“Defaulting Lender”: subject to the final paragraph of Section 2.20, any Lender, as reasonably determined by the Administrative Agent, that has (a) failed to fund any portion of its Loans within two (2) Business Days of the date required to be funded by it under this Agreement, unless such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, (b) notified the Borrower, the Administrative Agent or any other Lender in writing that it does not intend to comply with any of its funding obligations under this Agreement or has made a public statement to the effect that it does not intend to comply with its funding obligations under this Agreement (other than a notice of a good faith dispute or related communications) or generally under other agreements in which it commits to extend credit, unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s good faith determination that a condition precedent to funding (which condition precedent, together with any applicable Default, shall be specifically identified in such writing or public statement) cannot be satisfied, (c) failed, within two (2) Business Days after written request by the Administrative Agent or the Borrower, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Loans, unless the subject of a good faith dispute (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent or the Borrower), (d) otherwise failed to pay over to the Administrative Agent or any other Lender any other amount required to be paid by it under this Agreement within two (2) Business Days of the date when due, unless the subject of a good faith dispute, or (e) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had a custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment or has a parent company that has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment, or (iii) become the subject of a Bail-In Action; provided that (x) if a Lender would be a “Defaulting Lender” solely by reason of events relating to a parent company of such Lender or solely because a Governmental Authority has been appointed as receiver, conservator, trustee or custodian for such Lender, in each case as

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described in clause (e) above, the Administrative Agent may, in its discretion, determine that such Lender is not a “Defaulting Lender” if and for so long as the Administrative Agent is satisfied that such Lender will continue to perform its funding obligations hereunder and (y) a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of voting stock or any other Capital Stock in such Lender or a parent company thereof by a Governmental Authority or an instrumentality thereof, or the exercise of control over such Lender or parent company thereof, by a Governmental Authority or instrumentality thereof so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit

such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (a) through (e) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to the final paragraph of Section 2.20) upon delivery of written notice of such determination to the Borrower and each Lender.

“Disposition”: with respect to any property, any sale, lease, sale and leaseback, assignment, conveyance, transfer or other disposition thereof. The term “Dispose of” shall have a correlative meaning.

“Dollars” and “$”: dollars in lawful currency of the United States.

“EEA Financial Institution”: (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country”: any of the member states of the European Union, Iceland, Liechtenstein and Norway.

“EEA Resolution Authority”: any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Date”: the date on which the conditions precedent set forth in Section 5 shall have been satisfied or waived, which date is April 20, 2022.

“Eligible Assignee”: (a) any commercial bank or other financial institution having a senior unsecured debt rating by Moody’s of A3 or better and by S&P of A- or better, which is domiciled in a country which is a member of the OECD or (b) with

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respect to any Person referred to in the preceding clause (a), any other Person that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of business all of the Capital Stock of which is owned, directly or indirectly, by such Person; provided that in the case of clause (b), the Administrative Agent shall have consented to the designation of such Person as an Eligible Assignee (such consent not to be unreasonably withheld or delayed).

“Environmental Laws”: any and all foreign, Federal, state, local or municipal laws, rules, orders, regulations, statutes, ordinances, codes, decrees, requirements of any Governmental Authority or other Requirements of Law (including common law) regulating, relating to or imposing liability or standards of conduct concerning protection of human health or the environment, as now or may at any time hereafter be in effect.

“ERISA”: the Employee Retirement Income Security Act of 1974, as amended from time to time.

“ERISA Event”: (a) any Reportable Event; (b) the failure of the Borrower or any Commonly Controlled Entity to timely make a required contribution with respect to any Plan or any Multiemployer Plan; (c) the imposition of a Lien under Section 430 of the Code or Section 303 of ERISA with respect to any Single Employer Plan; (d) the failure of the Borrower or any Commonly Controlled Entity to meet the minimum funding standard under Section 412 or 430 of the Code with respect to any Plan or the filing of an application for a funding waiver with respect to any Single Employer Plan; (e) the incurrence by the Borrower or any Commonly Controlled Entity of any liability under Title IV of ERISA, including with respect to the termination of any Plan (other than the payment of PBGC premiums in the ordinary course); (f) (i) the termination of, or the filing or receipt of a notice of intent to terminate, a Single Employer Plan under Section 4041 of ERISA, or the treatment of a plan amendment as a termination under Section 4041 of ERISA, or (ii) (A) the appointment of a trustee to administer a Single Employer Plan under Section 4042 of ERISA, or (B) the institution by the PBGC of proceedings to terminate a Single Employer Plan or to have a trustee appointed to administer a Single Employer Plan, or receipt by the Borrower of notice from the PBGC thereof, where such proceedings continue unstayed or in effect for more than 60 days, or such notice is not withdrawn by the PBGC within 60 days following delivery by the PBGC; (g) the incurrence by the Borrower or any Commonly Controlled Entity of any liability with respect to the complete withdrawal or partial withdrawal under Title IV of ERISA from any Multiemployer Plan; (h) the receipt by the Borrower or any Commonly Controlled Entity of any notice from a Multiemployer Plan concerning the imposition of Withdrawal Liability; (i) receipt of notification by the Borrower or any Commonly Controlled Entity from a Multiemployer Plan that such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency; (j) the incurrence by the Borrower or any Commonly Controlled Entity of any liability pursuant to Section 4063 or 4064 of ERISA or a substantial cessation of operations with respect to a Plan within the meaning of Section 4062(e) of ERISA; (k) the posting of a bond or security under Section 436(f) of the Code with respect to any Plan; or (l) the incurrence by the

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Borrower of any material tax liability with respect to any Plan (including Sections 4975, 4980B, 4980D, 4980H and 4980I of the Code, as applicable).

“Erroneous Payment”: as defined in Section 9.13(a).

“EU Bail-In Legislation Schedule”: the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Event of Default”: any of the events specified in Section 8, provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Exchange Act”: the Securities Exchange Act of 1934, as amended.

“Excluded Taxes”: any of the following Taxes imposed on or with respect to any Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan (other than pursuant to an assignment request by the Borrower under Section 2.19) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.16(a) or (c), amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.16(e) and (d) any U.S. federal withholding Taxes imposed pursuant to FATCA.

“Extended FMB”: as defined in Section 2.7.

“Extended Loans”: as defined in Section 2.7.

“Extending Lender”: as defined in Section 2.7.

“Extension”: as defined in Section 2.7.

“Extension Effective Date”: as defined in Section 2.7.

“Extension Notice”: as defined in Section 2.7.

“FATCA”: Sections 1471 through 1474 of the Code, as of the Effective Date (or any amended or successor version that is substantively comparable and not materially

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more onerous to comply with), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Code.

“FCPA”: as defined in Section 4.15.

“Federal Funds Effective Rate”: for any day, the rate calculated by the NYFRB based on such day’s federal funds transactions by depositary institutions, as determined in such manner as shall be set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as the effective federal funds rate; provided that if the Federal Funds Effective Rate as so determined would be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Federal Reserve Board”: the Board of Governors of the Federal Reserve System of the United States of America.

“First Mortgage Bonds”: bonds issued by the Borrower pursuant to the FMB Indenture.

“Floor”: the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to the Adjusted Term SOFR Rate. For the avoidance of doubt, the initial Floor for each of the Adjusted Term SOFR Rate and Adjusted Daily Simple SOFR shall be 0.0%.

“FMB Indenture”: the Indenture of Mortgage (Mortgage), dated as of June 19, 2020, between the Borrower and the Indenture Trustee, as amended or supplemented from time to time, including as supplemented by the Supplemental Indenture.

“Foreign Lender”: a Lender that is not a U.S. Person.

“FPA”: the Federal Power Act, as amended, and the rules and regulations promulgated thereunder.

“Funding Office”: the office of the Administrative Agent specified in Section 10.2(a) or such other office as may be specified from time to time by the Administrative Agent as its funding office by written notice to the Borrower and the Lenders.

“GAAP”: generally accepted accounting principles in the United States as in effect from time to time, except as noted below. In the event that any “Change in Accounting Principles” (as defined below) shall occur and such change results in a change in the method of calculation of financial covenants, standards or terms in this Agreement, then, upon the request of the Borrower or the Required Lenders, the Borrower and the Administrative Agent agree to enter into negotiations in order to amend such provisions of this Agreement so as to reflect equitably such Change in Accounting Principles with the desired result that the criteria for evaluating the Borrower’s financial condition shall be the same after such Change in Accounting Principles as if such Change

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in Accounting Principles had not been made. Until such time as such an amendment shall have been executed and delivered by the Borrower, the Administrative Agent and the Required Lenders, all financial covenants, standards and terms in this Agreement shall continue to be calculated or construed as if such Change in Accounting Principles had not occurred. “Change in Accounting Principles” refers to (i) changes in accounting principles required by the promulgation of any rule, regulation, pronouncement or opinion by the Financial Accounting Standards Board of the American Institute of Certified Public Accountants or any successor thereto, the SEC or, if applicable, the Public Company Accounting Oversight Board and (ii) any change in the application of GAAP concurred by the Borrower’s independent public accountants and disclosed in writing to the Administrative Agent.

“Governmental Authority”: any nation or government, any state or other political subdivision thereof, any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, any securities

exchange and any self-regulatory organization (including the National Association of Insurance Commissioners and supra-national bodies such as the European Union or the European Central Bank).

“Guarantee Obligation”: as to any Person (the “guaranteeing person”), any obligation, including a reimbursement, counterindemnity or similar obligation, of the guaranteeing person that guarantees any Indebtedness, leases, dividends or other obligations (the “primary obligations”) of any other third Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of the guaranteeing person, whether or not contingent, (i) to purchase any such primary obligation or any property constituting direct or indirect security therefor, (ii) to advance or supply funds (1) for the purchase or payment of any such primary obligation or (2) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (iii) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation, (iv) otherwise to assure or hold harmless the owner of any such primary obligation against loss in respect thereof or (v) to reimburse or indemnify an issuer of a letter of credit, surety bond or guarantee issued by such issuer in respect of primary obligations of a primary obligor other than the Borrower or any Significant Subsidiary; provided, however, that the term Guarantee Obligation shall not include endorsements of instruments for deposit or collection in the ordinary course of business. The amount of any Guarantee Obligation of any guaranteeing person shall be deemed to be the lower of (a) an amount equal to the stated or determinable amount of the primary obligation in respect of which such Guarantee Obligation is made and (b) the maximum amount for which such guaranteeing person may be liable pursuant to the terms of the instrument embodying such Guarantee Obligation, unless such primary obligation and the maximum amount for which such guaranteeing person may be liable are not stated or determinable, in which case the amount of such Guarantee Obligation shall be such guaranteeing

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person’s reasonably anticipated liability in respect thereof as determined by the Borrower in good faith.

“Indebtedness”: of any Person at any date, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person for the deferred purchase price of property or services (other than trade payables, including under energy procurement and transportation contracts, incurred in the ordinary course of such Person’s business), (c) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (e) all Capital Lease Obligations of such Person, (f) all obligations of such Person, contingent or otherwise, as an account party or applicant under or in respect of acceptances, letters of credit, surety bonds or similar arrangements (other than reimbursement obligations, which are not due and payable on such date, in respect of documentary letters of credit issued to provide for the payment of goods and services in the ordinary course of business), (g) the liquidation value of all mandatorily redeemable preferred Capital Stock of such Person, (h) all Guarantee Obligations of such Person in respect of obligations of the kind referred to in clauses (a) through (g) above, (i) all obligations of the kind referred to in clauses (a) through (h) above secured by (or for which the holder of such obligation has an existing right, contingent or otherwise, to be secured by) any Lien on property (including accounts and contract rights) owned by such Person, whether or not such Person has assumed or become liable for the payment of such obligation (provided, that if such Person is not liable for such obligation, the amount of such Person’s Indebtedness with respect thereto shall be deemed to be the lesser of the stated amount of such obligation and the value of the property subject to such Lien), and (j) for the purposes of Section 8(e) only, all obligations of such Person in respect of Swap Agreements, provided that Indebtedness as used in this Agreement shall exclude any Non-Recourse Debt and any obligations under any A/R Securitization Transaction. The Indebtedness of any Person shall include the Indebtedness of any other entity (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness expressly provide that such Person is not liable therefor.

“Indemnified Liabilities”: as defined in Section 10.5.

“Indemnified Taxes”: (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“Indemnitee”: as defined in Section 10.5.

“Indenture Trustee”: The Bank of New York Mellon Trust Company, N.A. and any successor thereto as trustee under the FMB Indenture.

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“Insolvency”: with respect to any Multiemployer Plan, the condition that such plan is insolvent within the meaning of Section 4245 of ERISA.

“Interest Payment Date”: (a) as to any ABR Loan, the last day of each March, June, September and December to occur while such Loan is outstanding and the final maturity date of such Loan, (b) with respect to any RFR Loan, each date that is on the numerically corresponding day in each calendar month that is one month after the Borrowing of such Loan (or, if there is no such numerically corresponding day in such month, then the last day of such month), (c) with respect to any Term Benchmark Loan, the last day of each Interest Period applicable to the Borrowing of which such Loan is a part and (d) as to any Loan, the date of any repayment or prepayment made in respect thereof.

“Interest Period”: as to any Term Benchmark Loan, (a) initially, the period commencing on the borrowing or conversion date, as the case may be, with respect to such Term Benchmark Loan and ending one month thereafter; and (b) thereafter, each period commencing on the last day of the next preceding Interest Period applicable to

such Term Benchmark Loan and ending one month thereafter; provided that, all of the foregoing provisions relating to Interest Periods are subject to the following:

(i)    if any Interest Period would otherwise end on a day that is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless the result of such extension would be to carry such Interest Period into another calendar month in which event such Interest Period shall end on the immediately preceding Business Day;

(ii)    the Borrower may not select an Interest Period that would extend beyond the Maturity Date;

(iii)    any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month;

(iv)    [reserved]; and

(v)    at the election of the Borrower, the initial Interest Period for any Term Benchmark Loans made on the Effective Date, shall commence on the Effective Date and end on the last day of the calendar month during which the Effective Date occurs.

“IRS”: the United States Internal Revenue Service.

“knowledge of the Borrower”: actual knowledge of any Responsible Officer of the Borrower.

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“Laws”: collectively, all international, foreign, federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.

“Lenders”: as defined in the preamble hereto, including each Lender set forth under the heading “Lender” on Schedule 1.1 and their respective successors and assigns as permitted hereunder; provided, that unless the context otherwise requires, each reference herein to the Lenders shall be deemed to include any Conduit Lender.

“Lien”: any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge or other security interest or any preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever (including any conditional sale or other title retention agreement and any

Capital Lease Obligation having substantially the same economic effect as any of the foregoing).

“Loans”: the 364-Day Tranche Loans.

“Loan Documents”: this Agreement, the Notes, the Supplemental Indenture, the Senior Bond, the Bond Delivery Agreement, the FMB Indenture and, in each case, any amendment, waiver, supplement or other modification to any of the foregoing; provided, that the term “Loan Documents” shall not include the FMB Indenture for any purposes under Section 2.16, Section 8 or Section 10 (other than for the purposes of Sections 10.1(b)(iv) and 10.1(b)(x)).

“Material Adverse Effect”: (a) a change in the business, property, operations or financial condition of the Borrower and its Subsidiaries taken as a whole that could reasonably be expected to materially and adversely affect the Borrower’s ability to perform its obligations under the Loan Documents or (b) a material adverse effect on (i) the validity or enforceability of this Agreement or any of the other Loan Documents or (ii) the rights and remedies of the Administrative Agent and the Lenders, taken as a whole, under this Agreement or any other Loan Document.

“Materials of Environmental Concern”: any gasoline or petroleum (including crude oil or any fraction thereof) or petroleum products or any hazardous or toxic substances, materials or wastes, defined or regulated as such in or under any Environmental Law, including asbestos, polychlorinated biphenyls and urea-formaldehyde insulation.

“Maturity Date”: with respect to the 364-Day Tranche Loans, the 364-Day Tranche Maturity Date.

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“Moody’s”: Moody’s Investors Service, Inc.

“Mortgaged Property”: as defined in the FMB Indenture.

“Multiemployer Plan”: a plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Tangible Assets”: the total amount of the Borrower’s assets determined on a consolidated basis in accordance with GAAP as of the last day of the most recently ended fiscal quarter for which financial statements have been delivered under Section 6.1, less (a) the sum of the Borrower’s consolidated current liabilities determined in accordance with GAAP, and (b) the amount of the Borrower’s consolidated assets classified as intangible assets, determined in accordance with GAAP.

“Non-Recourse Debt”: Indebtedness of the Borrower or any of its Significant Subsidiaries that is incurred in connection with the acquisition, construction, sale, transfer or other Disposition of specific assets, to the extent recourse, whether contractual or as a matter of law, for non-payment of such Indebtedness is limited (a) to such assets, or (b) if such assets are (or are to be) held by a Subsidiary formed solely for such purpose, to such Subsidiary or the Capital Stock of such Subsidiary.

“Notes”: as defined in Section 2.14(f).

“NYFRB”: the Federal Reserve Bank of New York.

“NYFRB Rate”: for any day, the greater of (a) the Federal Funds Effective Rate in effect on such day and (b) the Overnight Bank Funding Rate in effect on such day (or for any day that is not a Business Day, for the immediately preceding Business Day); provided that if neither of such rates are published for any day that is a Business Day, the term “NYFRB Rate” means the rate for a federal funds transaction quoted at 11:00 a.m. (New York City time) on such day received by the Administrative Agent from a federal funds broker of recognized standing selected by it; provided, further, that if any of the aforesaid rates as so determined would be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“NYFRB’s Website”: the website of the NYFRB at http://www.newyorkfed.org, or any successor source.

“Obligations”: the unpaid principal of and interest on (including, without limitation, interest accruing after the maturity of the Loans and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to the Borrower, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) the Loans and all other obligations and liabilities of the Borrower to the Administrative Agent or to any Lender, whether direct or indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, this

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Agreement, any other Loan Document or any other document made, delivered or given in connection herewith or therewith, whether on account of principal, interest, reimbursement obligations, fees, indemnities, costs, expenses (including, without limitation, all fees, charges and disbursements of counsel to the Administrative Agent or to any Lender that are required to be paid by the Borrower pursuant hereto) or otherwise.

“OECD”: the countries constituting the “Contracting Parties” to the Convention on the Organisation For Economic Co-operation and Development, as such term is defined in Article 4 of such Convention.

“Other Connection Taxes”: with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Other Taxes”: all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.19).

“Outbound Investment Rules”: the regulations administered and enforced, together with any related public guidance issued, by the United States Treasury Department under U.S. Executive Order 14105 of August 9, 2023, or any similar law or regulation as of the Amendment No. 5 Effective Date, and as codified at 31 C.F.R. § 850.101 et seq.

“Overnight Bank Funding Rate”: for any day, the rate comprised of overnight federal funds by U.S.-managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB as set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as an overnight bank funding rate.

“Participant”: as defined in Section 10.6(c).

“Participant Register”: as defined in Section 10.6(c)(iii).

“Patriot Act”: as defined in Section 10.16.

“Payment Recipient”: as defined in Section 9.13(a).

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“PBGC”: the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA (or any successor).

“PCG”: PG&E Corporation, a California corporation.

“Percentage”: as to any Lender at any time with respect to a Tranche, the percentage which the aggregate principal amount of such Lender’s Loans then outstanding constitutes of the aggregate principal amount of the Loans then outstanding with respect to such Tranche.

“Person”: an individual, partnership, corporation, limited liability company, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other entity of whatever nature.

“Plan”: at a particular time, any employee benefit plan that is covered by ERISA and in respect of which the Borrower or a Commonly Controlled Entity is (or, if such plan were terminated at such time, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

“Platform”: as defined in Section 10.2(d).

“Prime Rate”: the rate of interest last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Federal Reserve Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Administrative Agent) or in any similar release by the Federal Reserve Board (as determined by the Administrative Agent). Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

“PTE”: a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“QFC”: the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

“QFC Credit Support” in Section 10.19.

“Qualified Securitization Bond Issuer”: a Subsidiary of the Borrower formed and operating solely for the purpose of (a) purchasing and owning property created under a “financing order” (as such term is defined in the California Public Utilities Code) or similar order issued by the CPUC, (b) issuing such securities pursuant to such order, (c) pledging its interests in such property to secure such securities and (d) engaging in activities ancillary to those described in (a), (b) and (c).

“Recipient”: the Administrative Agent or any Lender.

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“Reference Time”: with respect to any setting of the then-current Benchmark means (1) if such Benchmark is the Term SOFR Rate, 5:00 a.m. (Chicago time) on the day that is two Business Days preceding the date of such setting, (2) if such Benchmark is Daily Simple SOFR, then four Business Days prior to such setting or (3) if such Benchmark is neither of the Term SOFR Rate nor Daily Simple SOFR, the time determined by the Administrative Agent in its reasonable discretion.

“Register”: as defined in Section 10.6(b).

“Regulation U”: Regulation U of the Federal Reserve Board as in effect from time to time.

“Related Parties”: with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors, consultants, service providers and representatives of such Person and of such Person’s Affiliates.

“Relevant Governmental Body”: the Federal Reserve Board and/or the NYFRB, the CME Term SOFR Administrator, as applicable, or a committee officially endorsed or convened by the Federal Reserve Board and/or the NYFRB or, in each case, any successor thereto.

“Relevant Rate”: (i) with respect to any Term Benchmark Loan, the Adjusted Term SOFR Rate or (ii) with respect to any RFR Loan, Adjusted Daily Simple SOFR.

“Removal Effective Date”: as defined in Section 9.9(b).

“Reportable Event”: any of the events set forth in Section 4043(c) of ERISA, other than those events as to which the thirty-day notice period is waived under subsections .27, .28, .29, .30, .31, .32, .34 or .35 of PBGC Reg. § 4043.

“Required Lenders”: at any time, the holders of more than 50% of the aggregate Loans then outstanding. The Loans of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.

“Requirement of Law”: as to any Person, the Articles of Incorporation and By-Laws or other organizational or governing documents of such Person, and any law, treaty, rule or regulation or determination of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject.

“Resignation Effective Date”: as defined in Section 9.9(a).

“Resolution Authority”: with respect to any EEA Financial Institution, an EEA Resolution Authority and, with respect to any UK Financial Institution, a UK Resolution Authority.

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“Responsible Officer”: the chief executive officer, president, chief financial officer, treasurer or assistant treasurer of the Borrower, but in any event, with respect to financial matters, the chief financial officer, treasurer or assistant treasurer of the Borrower.

“RFR Loan”: a Loan that bears interest at a rate based on Adjusted Daily Simple SOFR.

“S&P”: Standard & Poor’s Global Ratings, a division of S&P Global Inc., and any successor thereto.

“Sanctions”: as defined in Section 4.15.

“SEC”: the Securities and Exchange Commission, any successor thereto and any analogous Governmental Authority.

“Securitized Bonds”: without duplication, securities, however denominated, that are (i) issued by a Qualified Securitization Bond Issuer, (ii) secured by or otherwise payable from charges authorized by the financing order referred to in clause (a) of the definition of “Qualified Securitization Bond Issuer,” and (iii) non-recourse to the Borrower or any of its Subsidiaries (other than the issuer of such securities).

“Senior Bond”: that certain First Mortgage Bond in the aggregate principal amount of $525,000,000600,000,000 issued to the Administrative Agent pursuant to the Supplemental Indenture on April 11, 2025the Amendment No. 5 Effective Date.

“Significant Subsidiary”: as defined in Article 1, Rule 1-02(w) of Regulation S-X of the Exchange Act as of the Effective Date, provided that notwithstanding the foregoing, no special purpose finance subsidiary, no A/R Securitization Subsidiary (or Subsidiaries of any A/R Securitization Subsidiary) nor any Qualified Securitization Bond Issuer (or Subsidiaries of any Qualified Securitization Bond Issuer) shall constitute a Significant Subsidiary. Unless otherwise qualified, all references to a “Significant Subsidiary” or to “Significant Subsidiaries” in this Agreement shall refer to a “Significant Subsidiary” or “Significant Subsidiaries” of the Borrower.

“Single Employer Plan”: any Plan that is covered by Title IV of ERISA, but that is not a Multiemployer Plan.

“SOFR”: a rate equal to the secured overnight financing rate as administered by the SOFR Administrator.

“SOFR Administrator”: the NYFRB (or a successor administrator of the secured overnight financing rate).

“SOFR Administrator’s Website”: the NYFRB’s website, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the SOFR Administrator from time to time.

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“SOFR Rate Day”: has the meaning specified in the definition of “Daily Simple SOFR”.

“Solvent”: with respect to the Borrower and its Subsidiaries, on a consolidated basis, that as of the date of determination, (i) the fair value of the assets of the Borrower and its Subsidiaries, on a consolidated basis, at a fair valuation on a going concern basis, exceeds, on a consolidated basis, their debts and liabilities, subordinated, contingent or otherwise, (ii) the present fair saleable value of the property of the Borrower and its Subsidiaries, on a consolidated and going concern basis, is greater than the amount that will be required to pay the probable liability, on a consolidated basis, of their debts and other liabilities, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured in the ordinary course of business, (iii) the Borrower and its Subsidiaries, on a consolidated basis, are able to pay their debts and liabilities, subordinated, contingent or otherwise, as such liabilities become absolute and matured in the ordinary course of business, and (iv) the Borrower and its Subsidiaries are not engaged in businesses, and are not about to engage in businesses for which they have unreasonably small capital. For purposes of this definition, the amount of any contingent liability at any time shall be computed as the amount that, in light of all the facts and circumstances existing as of the Effective Date, would reasonably be expected to become an actual and matured liability.

“Specified Exchange Act Filings”: the Borrower’s Form 10-K annual report for the year ended December 31, 20232024 and each and all of the Form 10-Qs and Form 8-Ks (and to the extent applicable proxy statements) filed by the Borrower or PCG with the SEC after December 31, 20232024 and prior to the date that is one Business Day before the Amendment No. 5 Effective Date.

“Standard A/R Securitization Obligations”: representations, warranties, covenants, indemnities, repurchase obligations, servicing obligations, guarantees, intercompany notes and obligations relating to contributions of A/R Securitization Assets to an A/R Securitization Subsidiary and other obligations entered into by the Borrower or any of its Subsidiaries which are reasonably customary in A/R Securitization Transactions.

“Subsidiary”: as to any Person, a corporation, partnership, limited liability company or other entity of which shares of stock or other ownership interests having ordinary voting power (other than stock or such other ownership interests having such power only by reason of the happening of a contingency) to elect a majority of the board of directors or other managers of such corporation, partnership or other entity are at the time owned, or the management of which is otherwise controlled, directly or indirectly through one or more intermediaries, or both, by such Person. Unless otherwise qualified, all references to a “Subsidiary” or to “Subsidiaries” in this Agreement shall refer to a Subsidiary or Subsidiaries of the Borrower.

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“Supplemental Indenture”: with respect to the Senior Bond, the Fifteenth Supplemental Indenture, dated as of the Effective Date, by and between the Borrower and the Indenture Trustee.

“Supported QFC”: as defined in Section 10.19.

“Swap Agreement”: any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or any of its Subsidiaries shall be a “Swap Agreement”.

“Taxes”: all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Term Benchmark”: when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted Term SOFR Rate.

“Term SOFR Determination Day”: has the meaning assigned to it under the definition of Term SOFR Rate.

“Term SOFR Rate”: with respect to any Term Benchmark Borrowing and for any tenor comparable to the applicable Interest Period, the Term SOFR Reference Rate at approximately 5:00 a.m., Chicago time, two U.S. Government Securities Business Days prior to the commencement of such tenor comparable to the applicable Interest Period (such day, the “Term SOFR Determination Day”), as such rate is published by the CME Term SOFR Administrator.

“Term SOFR Reference Rate”: for any day and time, with respect to any Term Benchmark Borrowing denominated in Dollars and for any tenor comparable to the applicable Interest Period, the rate per annum determined by the Administrative Agent as the forward-looking term rate based on SOFR. If by 5:00 p.m. (New York City time) on the Term SOFR Determination Day, the “Term SOFR Reference Rate” for the applicable tenor has not been published by the CME Term SOFR Administrator and a Benchmark Replacement Date with respect to the Term SOFR Rate has not occurred, then the Term SOFR Reference Rate for such Term SOFR Determination Day will be the Term SOFR Reference Rate as published in respect of the first preceding U.S. Government Securities Business Day for which such Term SOFR Reference Rate was published by the CME Term SOFR Administrator, so long as such first preceding

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Business Day is not more than five (5) Business Days prior to such Term SOFR Determination Day.

“Tranche”: the 364-Day Tranche Commitments, the Amendment No. 5 Commitments or the 364-Day Tranche Loans.

“Transferee”: any Assignee or Participant.

“Type”: as to any Loan, its nature as an ABR Loan or a Term Benchmark Loan.

“UK Financial Institution”: any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority)) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority”: the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“Unadjusted Benchmark Replacement”: the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“United States” or “U.S.”: the United States of America.

“U.S. Government Securities Business Day”: any day except for (i) a Saturday, (ii) a Sunday or (iii) a day on which the Securities Industry and Financial Markets Association recommends that the fixed income departments of its members be closed for the entire day for purposes of trading in United States government securities.

“U.S. Person”: any Person that is(i) for purposes of Sections 4.22 and 7.8 hereof, any United States citizen, lawful permanent resident, entity organized under the laws of the United States or any jurisdiction within the United States, including any foreign branch of any such entity, or any person in the United States and (ii) for all other purposes, a “United States Person” as defined inperson” within the meaning of Section 7701(a)(30) of the Code.

“U.S. Special Resolution Regime”: as defined in Section 10.19.

“U.S. Tax Compliance Certificate”: as defined in Section 2.16(e)(ii)(B)(III).

“Withdrawal Liability”: any liability to a Multiemployer Plan as a result of a complete or partial withdrawal by the Borrower or any Commonly Controlled Entity from such Multiemployer Plan, as such terms are defined in Title IV of ERISA.

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“Write-Down and Conversion Powers”: (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the applicable Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to any UK Resolution Authority, any powers of such UK Resolution Authority under the applicable Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

1.2    Other Definitional Provisions and Interpretative Provisions.

Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in the other Loan Documents or any certificate or other document made or delivered pursuant hereto or thereto.

As used herein and, except as otherwise provided therein, in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, (i) accounting terms relating to the Borrower and its Significant Subsidiaries defined in Section 1 and accounting terms partly defined in Section Section 1, to the extent not defined, shall have the respective meanings given to them under GAAP, (ii) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (iii) the word “incur” shall be construed to mean incur, create, issue, assume or become liable in respect of (and the words “incurred” and “incurrence” shall have correlative meanings), (iv) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, Capital Stock, securities, revenues, accounts, leasehold interests and contract rights, and (v) references to agreements or other Contractual Obligations shall, unless otherwise specified, be deemed to refer to such agreements or Contractual Obligations as amended, supplemented, restated or otherwise modified from time to time.

The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.

The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

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The Borrower shall not be required to perform, nor shall it be required to guarantee the performance of, any of the affirmative covenants set forth in Section 6 that apply to any of its Significant Subsidiaries nor shall any of the Borrower’s Significant Subsidiaries be required to perform, nor shall any of such Significant Subsidiaries be required to guarantee the performance of, any of the Borrower’s affirmative covenants set forth in Section 6 or any of the affirmative covenants set forth in Section 6 that apply to any other Significant Subsidiary; provided, that nothing in this Section 1.2(e) shall prevent the occurrence of a Default or an Event of Default arising out of the Borrower’s failure to cause any Significant Subsidiary to comply with the provisions of this Agreement applicable to such Significant Subsidiary.

Notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any change in accounting for leases pursuant to GAAP resulting from the implementation of Financial Accounting Standards Board ASU No. 2016-02, Leases (Topic 842), to the extent such adoption would require treating any lease (or similar arrangement conveying the right to use) as a capital lease where such lease (or similar arrangement) would not have been required to be so treated under GAAP as in effect on December 31, 2015.

1.3    Divisions. For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized and acquired on the first date of its existence by the holders of its Capital Stock at such time.

1.4    Interest Rates; Benchmark Notification. The interest rate on a Loan denominated in Dollars may be derived from an interest rate benchmark that may be

discontinued or is, or may in the future become, the subject of regulatory reform. Upon the occurrence of a Benchmark Transition Event, Section 2.13(b) provides a mechanism for determining an alternative rate of interest. The Administrative Agent does not warrant, nor accept responsibility, nor shall the Administrative Agent have any liability with respect to the administration, submission or any other matter related to any reference rate referred to herein or with respect to any rate (including, for the avoidance of doubt, the selection of such rate and any related spread or other adjustment) that is an alternative or replacement for or successor to any such rate (including, without limitation, any Benchmark Replacement) (or any component of any of the foregoing) or the effect of any of the foregoing, or of any Benchmark Replacement Conforming Changes. The Administrative Agent and its affiliates or other related entities may engage in transactions or other activities that affect any reference rate referred to herein, or any alternative, successor or replacement rate (including, without limitation, any Benchmark Replacement) (or any component of any of the foregoing) or any related spread or other

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adjustments thereto, in each case, in a manner adverse to the Borrower. The Administrative Agent may select information sources or services in its reasonable discretion to ascertain any reference rate referred to herein or any alternative, successor or replacement rate (including, without limitation, any Benchmark Replacement) (or any component of any of the foregoing), in each case pursuant to the terms of this Agreement, and shall have no liability to the Borrower, any Lender or any other person or entity for damages of any kind, including direct or indirect, special, punitive, incidental or consequential damages, costs, losses or expenses (whether in tort, contract or otherwise and whether at law or in equity), for any error or other action or omission related to or affecting the selection, determination, or calculation of any rate (or component thereof) provided by any such information source or service.

SECTION 2.    AMOUNT AND TERMS OF THE TERM LOANS

2.1    Loans.

Subject to the terms and conditions set forth herein and in Amendment No. 3, each 364-Day Tranche Lender (severally and not jointly) agrees to be deemed to have made a term loan (the “Amendment No. 3 Loans”, and together with the Amendment No. 5 Loans, the “364-Day Tranche Loans”) to the Borrower in Dollars on the Amendment No. 3 Effective Date in an amount equal to such 364-Day Tranche Lender’s 364-Day Tranche Commitment. Loans under the 364-Day Tranche may be ABR Loans or Term Benchmark Loans, as further provided herein as of the Amendment No. 3 Effective Date. 364-Day Tranche Loans borrowed under this Section 2.1(a) and paid or prepaid may not be reborrowed.

(b)    [Reserved].

(a)    Subject to the terms and conditions set forth herein and in Amendment No. 5, each 364-Day Tranche Lender (severally and not jointly) agrees to make a term loan (the “Amendment No. 5 Loans”) to the Borrower in Dollars on the Amendment No. 5 Effective Date in an amount equal to such 364-Day Tranche Lender’s Amendment

No. 5 Commitment as of the Amendment No. 5 Effective Date. 364-Day Tranche Loans borrowed under this Section 2.1(b) and paid or prepaid may not be reborrowed.

(b)    364-Day Tranche Loans may be ABR Loans or Term Benchmark Loans, as further provided herein.

2.2    Procedures for Borrowing. The Borrower shall give the Administrative Agent irrevocable notice (which notice must be received by the Administrative Agent (a) prior to 12:00 Noon, New York City time, three Business Days prior to the Effective Date, in the case of Term Benchmark Loans, or (b) prior to 1:00 P.M., New York City time, one Business Day prior to the Effective Date, in the case of ABR Loans) specifying (i) the amount and Type of Loans to be borrowed on the Effective Date and (ii) in the case of Term Benchmark Loans, the respective amounts of each such Type of Loan and

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the respective lengths of the initial Interest Period therefor. Upon receipt of any such notice from the Borrower, the Administrative Agent shall promptly notify each Lender thereof. Each Lender will make the amount of its pro rata share of each borrowing available to the Administrative Agent for the account of the Borrower at the Funding Office prior to 10:00 A.M., New York City time, on the Effective Date in funds immediately available to the Administrative Agent. Such borrowing will then be made available to the Borrower by the Administrative Agent crediting the account of the Borrower on the books of such office with the aggregate of the amounts made available to the Administrative Agent by the Lenders and in like funds as received by the Administrative Agent.

2.3    [Reserved].

2.4    [Reserved].

2.5    [Reserved].

2.6    Fees, Etc.

The Borrower agrees to pay to the Administrative Agent, for the account of each Lender (other than a Defaulting Lender to the extent provided in Section 2.20), any fees payable in the amounts and at the times separately agreed upon between the Borrower and the Lenders.

The Borrower agrees to pay to the Administrative Agent the fees in the amounts and on the dates as set forth in any written, duly executed fee agreements with the Administrative Agent and to perform any other obligations contained therein.

(c)    [Reserved].

2.7    Termination of Commitments. The Commitments shall automatically terminate in full on the Amendment No. 3 Effective Date after the proceeds of the Loans have been deemed to have been made available to the Borrower.

2.7    Termination of Commitments; Extension of Maturity Date.

(a)    (i) The 364-Day Commitments shall automatically terminate in full on the Amendment No. 3 Effective Date after the proceeds of the Amendment No. 3 Loans have been deemed to have been made available to the Borrower and (ii) the Amendment No. 5 Commitments shall automatically terminate in full on the Amendment No. 5 Effective Date after the proceeds of the Amendment No. 5 Loans have been made available to the Borrower.

(b)    The Borrower may, on one occasion, by written notice to the Administrative Agent (such notice being an “Extension Notice”), given not earlier than 45 days and not later than 15 days prior to June 21, 2026, request the Lenders to consider an extension of the then applicable Maturity Date to June 20, 2027 (the “Extension”).

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The Administrative Agent shall promptly transmit the Extension Notice to each Lender. Each Lender shall notify the Administrative Agent whether it wishes to extend the then applicable Maturity Date not later than 10 days after the date of the Extension Notice, and any such notice given by a Lender to the Administrative Agent, once given, shall be irrevocable as to such Lender. Any Lender which does not expressly notify the Administrative Agent prior to the expiration of such ten-day period that it wishes to so extend the then applicable Maturity Date shall be deemed to have rejected the Borrower’s request for extension of such Maturity Date. Lenders consenting to extend the then applicable Maturity Date are hereinafter referred to as “Extending Lenders” and the Loans held by such Lender are referred to herein as “Extended Loans”. If all Lenders have elected (in their sole and absolute discretion) to so extend the Maturity Date, the Administrative Agent shall promptly notify the Borrower of such election by the Lenders, and effective on June 21, 2026 (the “Extension Effective Date”), the Maturity Date shall be automatically and immediately so extended to June 20, 2027, with regard to the Extending Lenders. No extension will be permitted hereunder without the consent of all of the Lenders. Upon the delivery of an Extension Notice and upon the extension of the Maturity Date pursuant to this Section, the Borrower shall be deemed to have represented and warranted on and as of the date of such Extension Notice and the effective date of such extension, as the case may be, that no Default or Event of Default has occurred and is continuing. Notwithstanding anything contained in this Agreement to the contrary, no Lender shall have any obligation to extend the Maturity Date, and each Lender may at its option, unconditionally and without cause, decline to extend the Maturity Date.

(c)    If the Maturity Date shall have been extended in accordance with this Section 2.7, all references herein to the “Maturity Date” shall refer to the Maturity Date as so extended.

(d)    If any Lender shall determine (or be deemed to have determined) not to extend the Maturity Date as requested by any Extension Notice given by the Borrower pursuant to this Section, the Commitment of such Lender shall terminate on the Maturity Date without giving any effect to such proposed extension, and the Borrower shall on such date pay to the Administrative Agent, for the account of such Lender, the principal amount of, and accrued interest on, such Lender’s Loans, together with any amounts

payable to such Lender pursuant to Section 2.17 and any and all fees or other amounts owing to such Lender under this Agreement.

(e)    The terms of the Extended Loans will be set forth in the Extension Notice and as agreed between the Borrower and the Extending Lenders; provided that:

(i)    except as to maturity, the terms and conditions of such Extended Loans are identical to those applicable to the Loans subject to such Extension Notice; and

(ii)    the Borrower shall have caused to be issued to the Administrative Agent a new First Mortgage Bond with respect to the Extended

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Loans (the “Extended FMB”) in the amount of the aggregate principal amount of the Loans then outstanding, such that the maturity date of such Senior Bond will be June 20, 2027 (after giving effect to the Extension). Upon receipt of the Extended FMB, the Administrative Agent shall return to the Borrower the original First Mortgage Bond of the Forty-Ninth Series in the amount of $600,000,000 issued on the Amendment No. 5 Effective Date. In addition, the Administrative Agent shall have received:

(A)    the Extended FMB, duly issued and authenticated under the FMB Indenture and in a form reasonably satisfactory to the Administrative Agent;

(B)    a certificate of a duly authorized officer of the Indenture Trustee certifying that the Extended FMB has been authenticated and is outstanding under the FMB Indenture;

(C)    copies of all other documents delivered to the Indenture Trustee by or on behalf of the Borrower on or prior to the Extension Effective Date in connection with the issuance of the Extended FMB (including, as it relates to the new maturity date of the Extended FMB, all other documents required under the procedures identified in Sections 601 of the Fifteenth Supplemental Indenture); and

(D)    copies of all title reports and commitments, if any, as of the Extension Effective Date with respect to the Mortgaged Property consisting of real property as to which Liens in favor of the Indenture Trustee, for the benefit of the holders of the Extended FMB, has been granted.

2.8    Optional Prepayments. The Borrower may at any time and from time to time prepay the Loans, in whole or in part, without premium or penalty, upon irrevocable notice delivered to the Administrative Agent no later than 12:00 Noon, New York City time, three Business Days prior thereto, in the case of Term Benchmark Loans, and no later than 2:00 p.m., New York City time, one Business Day prior thereto, in the case of ABR Loans, which notice shall specify the date and amount of prepayment and whether the prepayment is of Term Benchmark Loans or ABR Loans. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof. If any such notice is given, the amount specified in such notice shall be due and payable on the date specified therein, together with accrued interest to such date on the amount prepaid. Partial prepayments of Loans shall be in an aggregate principal amount of $1,000,000 or a whole multiple of $500,000 in excess thereof. Notwithstanding the foregoing, any notice of prepayment delivered in connection with any refinancing of all of the Loans with the proceeds of such refinancing or of any other incurrence of Indebtedness or the occurrence of some other identifiable event or condition, may be, if expressly so stated to be, contingent upon the consummation of such refinancing or incurrence or occurrence of such other identifiable event or condition and may be

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revoked by the Borrower, subject to compliance with the obligations under Section 2.17 in connection with any such revocation, in the event such contingency is not met. Each prepayment of Loans shall be accompanied by accrued interest and fees on the amount prepaid to the date fixed for prepayment plus, in the case of any Term Benchmark Loans that are prepaid on any day other than the last day of the Interest Period applicable to it, the Borrower shall pay any amounts due to the Lenders as a result thereof pursuant to Section 2.17.

2.9    Conversion and Continuation Options.

(a)    The Borrower may elect from time to time to convert Term Benchmark Loans to ABR Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the Business Day preceding the proposed conversion date, provided that any such conversion of Term Benchmark Loans may only be made on the last day of an Interest Period with respect thereto. The Borrower may elect from time to time to convert ABR Loans to Term Benchmark Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the third Business Day preceding the proposed conversion date (which notice shall specify the length of the initial Interest Period therefor), provided that no ABR Loan may be converted into a Term Benchmark Loan when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such conversions. Upon receipt of any such notice the Administrative Agent shall promptly notify each Lender.

(b)    Any Term Benchmark Loan may be continued as such upon the expiration of the then current Interest Period with respect thereto by the Borrower giving irrevocable notice to the Administrative Agent, in accordance with the applicable provisions of the defined term “Interest Period”, of the length of the next Interest Period to be applicable to such Loans, provided that no Term Benchmark Loan may be continued as such when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such continuations; provided, further, that if the Borrower shall fail to give any required notice as described above in this paragraph, subject to the preceding proviso, such Loans shall be automatically continued as Term Benchmark Loans with an Interest Period of one month on the last day of such then expiring Interest Period. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.

2.10    Limitations on Term Benchmark Loans. Notwithstanding anything to the contrary in this Agreement, all borrowings, conversions and continuations of Term Benchmark Loans and all selections of Interest Periods shall be in such amounts and be made pursuant to such elections so that no more than five (5) Interest Periods shall be outstanding at any one time.

2.11    Interest Rates and Payment Dates.

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(a)    Each Term Benchmark Loan shall bear interest for each day during each Interest Period with respect thereto at a rate per annum equal to the Term Benchmark determined for such day plus the Applicable Margin.

(b)    Each ABR Loan shall bear interest at a rate per annum equal to the ABR plus the Applicable Margin.

(c)    (i) If all or a portion of the principal amount of the Loans shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate that would otherwise be applicable thereto pursuant to the foregoing provisions of this Section plus 2% and (ii) if all or a portion of any interest payable on the Loans or any other fee payable in connection herewith (excluding any expenses or other indemnity) shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate then applicable to ABR Loans plus 2%, in each case, with respect to clauses (i) and (ii) above, from the date of such non-payment until such amount is paid in full (as well after as before judgment).

(d)    Interest shall be payable in arrears on each Interest Payment Date, provided that interest accruing pursuant to Section 2.11(c) shall be payable from time to time on demand.

(e)    The amount of each interest payment received by the Administrative Agent under the Senior Bond shall be deemed to be a payment of interest payable by the Borrower hereunder and shall reduce, dollar-for-dollar, the amount of interest then owing by the Borrower hereunder.

2.12    Computation of Interest and Fees.

(a)    Interest and fees payable pursuant hereto shall be calculated on the basis of a 360-day year for the actual days elapsed, except that, with respect to ABR Loans the rate of interest on which is calculated on the basis of ABR, the interest thereon shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of each determination of a Term Benchmark. Any change in the interest rate on a Loan resulting from a change in the ABR or the Term Benchmark shall become effective as of the opening of business on the day on which such change becomes effective. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of the effective date and the amount of each such change in interest rate.

(b)    Each determination of an interest rate by the Administrative Agent pursuant to any provision of this Agreement shall constitute prima facie evidence of such amounts. The Administrative Agent shall, at the request of the Borrower or any Lender,

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deliver to the Borrower or such Lender a statement showing the quotations used by the Administrative Agent in determining any interest rate pursuant to Section 2.11(a).

2.13    Inability to Determine Interest Rate.

(a)    Subject to clauses (b), (c), (d), (e) and (f) of this Section 2.13, if:

(i)    the Administrative Agent determines (which determination shall be conclusive absent manifest error) (A) prior to the commencement of any Interest Period for a Term Benchmark Loan, that adequate and reasonable means do not exist for ascertaining the Adjusted Term SOFR Rate or the Term SOFR Rate (including because the Term SOFR Reference Rate is not available or published on a current basis), for such Interest Period or (B) at any time, that adequate and reasonable means do not exist for ascertaining the applicable Adjusted Daily Simple SOFR or Daily Simple SOFR; or

(ii)    the Administrative Agent is advised by the Required Lenders that (A) prior to the commencement of any Interest Period for a Term Benchmark Loan, the Adjusted Term SOFR Rate for such Interest Period will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Term Benchmark Loan for such Interest Period or (B) at any time, Adjusted Daily Simple SOFR will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Term Benchmark Loan;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone, telecopy or electronic mail as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, any notice from the Borrower to the Administrative Agent that requests the conversion of any Loans to, or continuation of any Loans as, a Term Benchmark Loan shall instead be deemed to request the conversion of any Loans to, or continuation of any Loans as, (x) an RFR Loan so long as Adjusted Daily Simple SOFR is not also the subject of Section 2.13(a)(i) or (ii) above or (y) an ABR Borrowing if Adjusted Daily Simple SOFR also is the subject of Section 2.13(a)(i) or (ii) above.

(b)    Notwithstanding anything to the contrary herein or in any other Loan Document (and any Swap Agreement shall be deemed not to be a “Loan Document” for purposes of this Section 2.13), if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (x) if a Benchmark Replacement is

determined in accordance with clause (1) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any other Loan Document in respect of

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such Benchmark setting and subsequent Benchmark settings without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document and (y) if a Benchmark Replacement is determined in accordance with clause (2) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any other Loan Document in respect of any Benchmark setting at or after 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Required Lenders of each affected Class.

(c)    Notwithstanding anything to the contrary herein or in any other Loan Document, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Loan Document.

(d)    The Administrative Agent will promptly notify the Borrower and the Lenders of (i)any occurrence of a Benchmark Transition Event, (ii)the implementation of any Benchmark Replacement, (iii)the effectiveness of any Benchmark Replacement Conforming Changes, (iv)the removal or reinstatement of any tenor of a Benchmark pursuant to clause (f) below and (v)the commencement or conclusion of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 2.13, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party to this Agreement or any other Loan Document, except, in each case, as expressly required pursuant to this Section 2.13.

(e)    Notwithstanding anything to the contrary herein or in any other Loan Document, at any time (including in connection with the implementation of a Benchmark Replacement), (i) if the then-current Benchmark is a term rate (including the Term SOFR Rate) and either (A) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (B) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative, then the Administrative Agent may modify the definition of “Interest Period” for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor and (ii) if a tenor that was removed pursuant to clause (i) above either (A)is subsequently displayed on a screen or information service for a Benchmark

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(including a Benchmark Replacement) or (B)is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate such previously removed tenor.

(f)    Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a Term Benchmark Borrowing or conversion to or continuation of Term Benchmark Loans to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any request for a Term Benchmark Borrowing into a request for a Borrowing of or conversion to (A)an RFR Loan so long as Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (B) an ABR Borrowing if Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event. During any Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of ABR based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of ABR. Furthermore, if any Term Benchmark Loan is outstanding on the date of the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period with respect to a Relevant Rate applicable to such Term Benchmark Loan or RFR Loan, then until such time as a Benchmark Replacement is implemented pursuant to this Section 2.13, any Term Benchmark Loan shall on the last day of the Interest Period applicable to such Loan (or the next succeeding Business Day if such day is not a Business Day), be converted by the Administrative Agent to, and shall constitute, (x) an RFR Loan so long as Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (y) an ABR Loan if Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event, on such day.

2.14    Pro Rata Treatment and Payments; Notes.

(a)    [Reserved].

(b)    Each payment (including each prepayment) by the Borrower on account of principal of and interest on the Loans shall be made pro rata in the case of the 364-Day Tranche Loans, according to the respective outstanding principal amounts of the 364-Day Tranche Loans then held by the 364-Day Tranche Lenders.

(c)    Notwithstanding anything to the contrary herein, all payments (including prepayments) to be made by the Borrower hereunder, whether on account of principal, interest, fees or otherwise, shall be made without setoff or counterclaim and shall be made prior to 4:00 P.M., New York City time, on the due date thereof to the Administrative Agent, for the account of the Lenders at the Funding Office, in Dollars and in immediately available funds. The Administrative Agent shall distribute such payments to the Lenders promptly upon receipt in like funds as received. If any payment hereunder (other than payments on the Term Benchmark Loans) becomes due and

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payable on a day other than a Business Day, such payment shall be extended to the next succeeding Business Day. If any payment on a Term Benchmark Loan becomes due and payable on a day other than a Business Day, the maturity thereof shall be extended to the next succeeding Business Day unless the result of such extension would be to extend such payment into another calendar month, in which event such payment shall be made on the immediately preceding Business Day. In the case of any extension of any payment of principal pursuant to the preceding two sentences, interest thereon shall be payable at the then applicable rate during such extension.

(d)    Unless the Administrative Agent shall have been notified in writing by any Lender prior to a borrowing that such Lender will not make the amount that would constitute its share of such borrowing available to the Administrative Agent, the Administrative Agent may assume that such Lender is making such amount available to the Administrative Agent, and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower a corresponding amount. If such amount is not made available to the Administrative Agent by the required time on the Effective Date, such Lender shall pay to the Administrative Agent, on demand, such amount with interest thereon, at a rate equal to the greater of (i) the NYFRB Rate and (ii) a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation, for the period until such Lender makes such amount immediately available to the Administrative Agent. A certificate of the Administrative Agent submitted to any Lender with respect to any amounts owing under this paragraph shall be conclusive in the absence of manifest error. If such Lender’s share of such borrowing is not made available to the Administrative Agent by such Lender within three Business Days after the Effective Date, the Administrative Agent shall also be entitled to recover such amount with interest thereon at the rate per annum applicable to ABR Loans from the Borrower within 30 days after written demand therefor.

(e)    Unless the Administrative Agent shall have been notified in writing by the Borrower prior to the date of any payment due to be made by the Borrower hereunder that the Borrower will not make such payment to the Administrative Agent, the Administrative Agent may assume that the Borrower is making such payment, and the Administrative Agent may, but shall not be required to, in reliance upon such assumption, make available to the Lenders their respective pro rata shares of a corresponding amount. If such payment is not made to the Administrative Agent by the Borrower within three Business Days after such due date, the Administrative Agent shall be entitled to recover, on demand, from each Lender to which any amount which was made available pursuant to the preceding sentence, such amount with interest thereon at the rate per annum equal to the NYFRB Rate. Nothing herein shall be deemed to limit the rights of the Administrative Agent or any Lender against the Borrower.

(f)    The Borrower agrees that, upon the request to the Administrative Agent by any Lender, the Borrower will promptly execute and deliver to such Lender a promissory note (a “Note”) of the Borrower evidencing any Loans (or any portion thereof) of such Lender, substantially in the form of Exhibit H, with appropriate insertions as to date and

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principal amount; provided, that delivery of Notes shall not be a condition precedent to the occurrence of the Effective Date or the making of the Loans on the Effective Date.

(g)    If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.14(d), then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent hereunder for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations to the Administrative Agent, as the case may be, under such Section until all such unsatisfied obligations are fully paid, and/or (ii) so long as such Lender is a Defaulting Lender, hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

2.15    Change of Law.

(a)    If a Change of Law shall:

(i)    subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its Loans, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

(ii)    impose, modify or hold applicable any reserve, special deposit, compulsory loan, Federal Deposit Insurance Corporation insurance charge or other similar insurance charge or similar requirement against assets held by, deposits or other liabilities in or for the account of, advances, loans or other extensions of credit by, or any other acquisition of funds by, any Lender that is not otherwise included in the determination of the Term Benchmark Rate, which requirements are generally applicable to advances, loans and other extensions of credit made by such Lender; or

(iii)    impose on any Lender any other condition that is generally applicable to loans made by such Lender or participations therein;

and the result of any of the foregoing is to increase the cost to such Lender or such other Recipient, by an amount that such Lender or such other Recipient deems to be material, of making, converting into, continuing or maintaining the Loans, or to reduce any amount receivable hereunder in respect thereof, then, in any such case, the Borrower shall promptly pay such Lender or such other Recipient, within ten Business Days after its demand, any additional amounts necessary to compensate such Lender or such other Recipient for such increased cost or reduced amount receivable. If any Lender or other Recipient becomes entitled to claim any additional amounts pursuant to this paragraph, it shall promptly notify the Borrower (with a copy to the Administrative Agent) of the event

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by reason of which it has become so entitled; provided, however, that no Lender or other Recipient shall be entitled to demand such compensation more than 90 days following (x) the last day of the Interest Period in respect of which such demand is made or (y) the repayment of the Loan in respect of which such demand is made. Notwithstanding any other provision herein, no Lender shall demand compensation pursuant to this Section 2.14 if it shall not at the time be the general policy or practice of such Lender to demand such compensation from similarly situated borrowers (to the extent that such Lender has the right to do so under its credit facilities with similarly situated borrowers).

(b)    If any Lender shall have determined that a Change of Law regarding capital or liquidity requirements shall have the effect of reducing the rate of return on such Lender’s capital or the capital of any corporation controlling such Lender as a consequence of its obligations hereunder to a level below that which such Lender or such corporation could have achieved but for such Change of Law (taking into consideration such Lender’s or such corporation’s policies with respect to capital adequacy or liquidity) by an amount deemed by such Lender to be material, then from time to time, after submission by such Lender to the Borrower (with a copy to the Administrative Agent) of a written request therefor, the Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or such corporation for such reduction.

(c)    A certificate as to any additional amounts payable pursuant to this Section 2.14 submitted by any Lender or any other Recipient to the Borrower (with a copy to the Administrative Agent) shall constitute prima facie evidence of such costs or amounts. Notwithstanding anything to the contrary in this Section 2.14, the Borrower shall not be required to compensate a Lender or any other Recipient pursuant to this Section 2.14 for any amounts incurred more than six months prior to the date that such Lender or such other Recipient notifies the Borrower of such Lender’s or such other Recipient’s intention to claim compensation therefor; provided that, if the circumstances giving rise to such claim have a retroactive effect, then such six-month period shall be extended to include the period of such retroactive effect not to exceed twelve months. The obligations of the Borrower pursuant to this Section 2.14 shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts then due and payable hereunder.

2.16    Taxes.

(a)    Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by applicable laws. If any applicable laws (as determined in the good faith discretion of the Borrower or the Administrative Agent making the payment) require the deduction or withholding of any Tax from any such payment, then (A) the Borrower or the Administrative Agent, as applicable shall withhold or make such deductions as are determined by the Borrower or the Administrative Agent to be required, (B) the Borrower or the Administrative Agent, as applicable shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with such laws, and (C) to the extent that the withholding or deduction is made on account of

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Indemnified Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section 2.16) the applicable Recipient receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)    Without limiting the provisions of subsection (a) above, the Borrower shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(c)    (i) The Borrower shall, and does hereby, indemnify each Recipient, and shall make payment in respect thereof within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 2.16) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender or another Recipient (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender or another Recipient, shall be conclusive absent manifest error.

(ii)    Each Lender shall, and does hereby, severally indemnify, and shall make payment in respect thereof within 10 days after demand therefor, (x) the Administrative Agent against any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (y) the Administrative Agent against any Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.6(c)(iii) relating to the maintenance of a Participant Register and (z) the Administrative Agent against any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender, as the case may be, under this Agreement or any other Loan Document against any amount due to the Administrative Agent under this clause (ii).

(d)    Upon request by the Borrower or the Administrative Agent, as the case may be, after any payment of Taxes by the Borrower or by the Administrative Agent to a Governmental Authority as provided in this Section 2.16, the Borrower shall deliver to

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the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such

payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(e)    (i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Sections 2.16(e)(ii)(A), (ii) (B) and (ii) (D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)    Without limiting the generality of the foregoing,

(A)    any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(I) in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed copies of IRS Form W-8BEN or W-8BEN-

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E, as applicable, establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN or W-8BEN-E, as applicable, establishing an

exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(II) executed copies of IRS Form W-8ECI;

(III) in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit G-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or W-8BEN-E, as applicable; or

(IV) to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN or W-8BEN-E, as applicable, a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-2 or Exhibit G-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-4 on behalf of each such direct and indirect partner;

(C)    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by

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applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)    if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the

Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3) (C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the Effective Date.

(iii)    Each Lender agrees that if any form or certification it previously delivered pursuant to this Section 2.16 expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(f)    At no time shall the Administrative Agent have any obligation to file for or otherwise pursue on behalf of a Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender, as the case may be. If any Recipient determines, in its sole discretion exercised in good faith, that it has received a refund of, or credit with respect to, any Taxes as to which it has been indemnified pursuant to this Section 2.16 (including by the payment of additional amounts pursuant to this Section 2.16), it shall pay to the Borrower an amount equal to such refund or credit (but only to the extent of indemnity payments made under this Section 2.16 with respect to the Taxes giving rise to such refund or credit), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund or credit). The Borrower, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (f) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event such indemnified party is required to repay such refund or credit to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (f), in no event will the indemnified party be required to pay any amount to the Borrower pursuant to this paragraph (f) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to

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indemnification and giving rise to such refund or credit had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph (f) shall not be construed to require any Recipient to make available its tax returns (or any other information relating to its Taxes that it deems confidential) to the Borrower or any other Person.

(g)    Each party’s obligations under this Section 2.16 shall survive for one year after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

2.17    Indemnity. The Borrower agrees to indemnify each Lender for, and to hold each Lender harmless from, any loss (other than the loss of Applicable Margin) or expense that such Lender may sustain or incur as a consequence of (a) default by the Borrower in making a borrowing of, conversion into or continuation of Term Benchmark Loans after the Borrower has given a notice requesting the same in accordance with the provisions of this Agreement, (b) default by the Borrower in making any prepayment of or conversion from Term Benchmark Loans after the Borrower has given a notice thereof in accordance with the provisions of this Agreement or (c) the making of a prepayment of Term Benchmark Loans on a day that is not the last day of an Interest Period with respect thereto. A certificate as to any amounts payable pursuant to this Section submitted to the Borrower by any Lender shall be conclusive in the absence of manifest error. This covenant shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

2.18    Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.14 or 2.16 with respect to such Lender, it will, if requested by the Borrower, use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event with the object of avoiding the consequences of such event; provided, that such designation is made on terms that, in the sole but reasonable judgment of such Lender, cause such Lender and its lending office(s) to suffer no unreimbursed economic disadvantage or any legal or regulatory disadvantage, and provided, further, that nothing in this Section shall affect or postpone any of the obligations of the Borrower or the rights of any Lender pursuant to Section 2.14 or 2.16.

2.19    Replacement of Lenders. The Borrower shall be permitted to replace any Lender that (a) requests (on its behalf or any of its Participants) reimbursement for amounts owing pursuant to Section 2.14 or 2.16, (b) provides notice under Section 2.21 or (c) becomes a Defaulting Lender, with a replacement financial institution; provided that (i) such replacement does not conflict with any Requirement of Law, (ii) no Event of Default shall have occurred and be continuing at the time of such replacement, (iii) prior to any such replacement, such Lender shall have taken no action under Section 2.18 which eliminates the continued need for payment of amounts owing pursuant to Section 2.14 or 2.16, (iv) the replacement financial institution shall purchase, at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (v) the Borrower shall be liable to such replaced Lender under Section 2.17 if any Term

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Benchmark Loan owing to such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto, (vi) the replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (vii) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein), (viii) until such time as such replacement shall be consummated, the Borrower shall pay all additional amounts (if any) required pursuant to Section 2.14 or 2.16, as the case may be, and (ix) any such replacement shall not be deemed to be a waiver of any rights that the Borrower, the Administrative Agent or any other Lender shall have against the replaced Lender.

2.20    Defaulting Lenders. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as that Lender is no longer a Defaulting Lender, to the extent permitted by applicable law:

(a)    any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Section 7 or otherwise, and including any amounts made available to the Administrative Agent by that Defaulting Lender pursuant to Section 9.7), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Borrower with the consent of the Administrative Agent, not to be unreasonably withheld, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of that Defaulting Lender to fund Loans under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and sixth, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of the Loans in respect of which that Defaulting Lender has not fully funded its appropriate share such payment shall be applied solely to pay the Loans of all non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Loans of that Defaulting Lender. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 2.20(a) shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto;

(b)    [Reserved];

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(c)    [Reserved];

(d)    [Reserved]; and

(e)    that Defaulting Lender’s right to approve or disapprove any amendment, supplement, modification, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of “Required Lenders” and Section 10.

If the Borrower and the Administrative Agent reasonably determine in writing that a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein (which may

include arrangements with respect to any cash collateral), that Lender will, to the extent applicable, purchase that portion of outstanding Loans of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Loans to be held on a pro rata basis by the Lenders in accordance with their Percentages, whereupon that Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

SECTION 3.    [RESERVED].

SECTION 4.    REPRESENTATIONS AND WARRANTIES

To induce the Administrative Agent and the Lenders to enter into this Agreement and to make the Loans, the Borrower hereby represents and warrants to the Administrative Agent and each Lender, on the Effective Date, that:

4.1    Financial Condition. The audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of December 31, 2023, and the related consolidated statements of income and cash flows for the fiscal year ended on such date, reported on by Deloitte & Touche LLP, in each case, (i) were prepared in accordance with GAAP consistently applied throughout the periods covered thereby, except as otherwise expressly noted therein, and (ii) present fairly in all material respects the consolidated financial condition of the Borrower and its consolidated Subsidiaries as of such date, and its consolidated income and its consolidated cash flows for the respective fiscal year then ended.

4.2    No Change. Since December 31, 2023, no Material Adverse Effect has occurred.

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4.3    Existence; Compliance with Law. Each of the Borrower and its Significant Subsidiaries (a) is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, (b) has the organizational power and organizational authority to own and operate its property, to lease the property it operates as lessee and to conduct the business in which it is currently engaged, (c) is duly qualified as a foreign corporation or other organization and in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification except to the extent that the failure to so qualify could not reasonably be expected to have a Material Adverse Effect and (d) is in compliance with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings and except to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

4.4    Power; Authorization; Enforceable Obligations. The Borrower has the corporate power and corporate authority to execute and deliver and to perform its obligations under the Loan Documents and to obtain extensions of credit hereunder. The Borrower has taken all necessary corporate action to authorize the execution and delivery of, and performance of its obligations under, the Loan Documents to which it is a party and to authorize the extensions of credit on the terms and conditions of this Agreement. No consent or authorization of, filing with, notice to or other act by or in respect of, any Governmental Authority or any other Person is required in connection with the extensions of credit hereunder or with the execution, delivery, performance, validity or enforceability of this Agreement or any of the Loan Documents, except (i) consents, authorizations, filings and notices which have been obtained or made and are in full force and effect, (ii) any consent, authorization or filing that may be required in the future the failure of which to make or obtain could not reasonably be expected to have a Material Adverse Effect and (iii) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies under the Loan Documents. This Agreement has been, and each other Loan Document upon execution and delivery will be, duly executed and delivered. This Agreement constitutes, and each other Loan Document upon execution will constitute, a legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforceability may be limited by (x) applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally, laws of general application related to the enforceability of securities secured by real estate and by general equitable principles (whether enforcement is sought by proceedings in equity or at law) and (y) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies hereunder or under the Loan Documents.

4.5    No Legal Bar. The execution and delivery of, and the performance of the obligations under, this Agreement and the other Loan Documents, the borrowing of the Loans hereunder and the use of the proceeds thereof will not violate in any material respect any Requirement of Law or any Contractual Obligation of the Borrower or any of its Significant Subsidiaries and will not result in, or require, the creation or imposition of

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any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Loan Documents and the FMB Indenture).

4.6    Litigation. (a) No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues with respect to any of the Loan Documents.

(b)    No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues, except as disclosed in the Specified

Exchange Act Filings, that could reasonably be expected to have a Material Adverse Effect.

4.7    No Default. No Default or Event of Default has occurred and is continuing.

4.8    Taxes. The Borrower and each of its Significant Subsidiaries has filed or caused to be filed all Federal and state returns of income and franchise taxes imposed in lieu of net income taxes and all other material tax returns that are required to be filed and has paid all taxes shown to be due and payable on said returns or with respect to any claims or assessments for taxes made against it or any of its property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable, and (ii) claims which could not reasonably be expected to have a Material Adverse Effect). No material tax Liens have been filed against the Borrower or any of its Significant Subsidiaries other than (A) Liens for taxes which are not delinquent or (B) Liens for taxes which are being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable.

4.9    Federal Regulations. No part of the proceeds of any Loans hereunder, will be used for “buying” or “carrying” any “margin stock” within the respective meanings of each of the quoted terms under Regulation U as now and from time to time hereafter in effect or for any purpose that violates the provisions of the Regulations of the Federal Reserve Board.

4.10    ERISA. No Reportable Event has occurred during the five year period prior to the date on which this representation is made or deemed made with respect to any Plan, and each Plan has complied with the applicable provisions of ERISA and the Code,

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except, in each case, to the extent that any such Reportable Event or failure to comply with the applicable provisions of ERISA or the Code could not reasonably be expected to result in a Material Adverse Effect. During the five year period prior to the date on which this representation is made or deemed made, there has been no (i) failure to make a required contribution to any Plan that would result in the imposition of a Lien or other encumbrance or the provision of security under Section 430 of the Code or Section 303 or 4068 of ERISA, or the arising of such a Lien or encumbrance; or (ii) “unpaid minimum required contribution” or “accumulated funding deficiency” (as defined or otherwise set forth in Section 4971 of the Code or Part 3 of Subtitle B of Title I of ERISA), whether or not waived, except, in each case, to the extent that such event could not reasonably be expected to result in a Material Adverse Effect. No termination of a Single Employer Plan has occurred, and no Lien in favor of the PBGC or a Plan has arisen, during such five-year period. The present value of all accrued benefits under each Single Employer Plan (based on those assumptions used to fund such Plan) did not, as of the last annual valuation date for which a certified actuarial valuation report is available prior to the date on which this representation is made or deemed made, exceed the value

of the assets of such Plan allocable to such accrued benefits, except as could not reasonably be expected to result in a Material Adverse Effect. Neither the Borrower nor any Commonly Controlled Entity has had a complete or partial withdrawal from any Multiemployer Plan during the five year period prior to the date on which this representation is made or deemed made that has resulted or could reasonably be expected to result in a material liability under ERISA, and neither the Borrower nor any Commonly Controlled Entity would become subject to any liability under ERISA if the Borrower or any such Commonly Controlled Entity were to withdraw completely from all Multiemployer Plans as of the valuation date most closely preceding the date on which this representation is made or deemed made, except as could not reasonably be expected to result in a Material Adverse Effect. No such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency.

4.11    Investment Company Act; Other Regulations. The Borrower is not an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended. On the Effective Date, the Borrower is not subject to regulation under any Requirement of Law (other than (a) Regulation X of the Federal Reserve Board and (b) Sections 817-830, and Sections 701 and 851 of the California Public Utilities Code) that limits its ability to incur Indebtedness under this Agreement.

4.12    Use of Proceeds. The proceeds of the Loans shall be used to pay fees, costs and expenses relating to the transactions contemplated hereby and for working capital and general corporate purposes.

4.13    Environmental Matters. Except as disclosed in the Specified Exchange Act Filings, the Borrower and its Significant Subsidiaries are not subject to any pending

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violations or liabilities under Environmental Laws or relating to the disposal, spill or other release of Materials of Environmental Concern that would reasonably be expected to have a Material Adverse Effect, and, to the knowledge of the Borrower, there are no facts, circumstances or conditions that could reasonably be expected to give rise to such violations or liabilities.

4.14    Regulatory Matters. Solely by virtue of the execution, delivery and performance of, or the consummation of the transactions contemplated by this Agreement, no Lender shall be or become subject to regulation (a) under the FPA or (b) as a “public utility” or “public service corporation” or the equivalent under any Requirement of Law.

4.15    Sanctions; Anti-Corruption. None of the Borrower, any of its Subsidiaries, nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its Subsidiaries is currently (i) the subject of any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department or the U.S. State Department (“Sanctions”) or (ii) located, organized or resident in a country or territory that is, or whose government is, the subject of any Sanctions. None of the Borrower, any of its Subsidiaries nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its

Subsidiaries, has taken any action, directly or indirectly, that would result in a violation in any material respect by any such Person of the United States Foreign Corrupt Practices Act of 1977, as amended (“FCPA”) or of any other anti-bribery or anti-corruption laws, rules, regulations legally applicable to such Persons (collectively, “Anti-Corruption Laws”). The Borrower will not use the proceeds of the Loans, or lend, contribute or otherwise make available such proceeds (a) to any Subsidiary, Affiliate, joint venture partner or other Person or entity, to fund the activities of any Person, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of any Sanctions, or (b) directly, or, to the knowledge of the Borrower, indirectly, for any payments to any governmental official or employee, political party, official of a political party, candidate for political office, or anyone else acting in an official capacity, in order to obtain, retain or direct business or obtain any improper advantage, in violation of the FCPA or of any Anti-Corruption Laws.

4.16    Affected Financial Institutions. The Borrower is not an Affected Financial Institution.

4.17    Solvency. The Borrower and its Subsidiaries, on a consolidated basis, are Solvent as of the Effective Date.

4.18    Disclosure.

(a)    All written information relating to the Borrower, its Subsidiaries and their respective businesses, other than any projections, estimates and other forward-

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looking materials and information of a general economic or industry specific nature, that has been provided by or on behalf of the Borrower to the Administrative Agent or the Lenders in connection with the transactions contemplated hereby does not, when taken as a whole, contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements contained therein not materially misleading in light of the circumstances under which such statements were made (giving effect to all supplements and updates thereto). Any projected information, estimates, other forward-looking materials and pro forma financial information that have been made available to any Lenders or the Administrative Agent prior to the Effective Date in connection with the transactions contemplated hereby have been prepared in good faith based upon assumptions believed by the Borrower to be reasonable as of the date such information was furnished to the Lenders and as of the Effective Date (it being understood that actual results may vary materially from such projections and pro forma information and such projections and pro forma information are not a guarantee of performance).

(b)    As of the Effective Date, to the knowledge of the Borrower, the information included in any Beneficial Ownership Certification provided on or prior to the Effective Date to any Lender in connection with this Agreement is true and correct in all respects.

4.19    Status of Obligations. The issuance to the Administrative Agent of the Senior Bond provides the Lenders, as beneficial holders of the Senior Bond through the

Administrative Agent, the benefit of the Lien of the FMB Indenture equally and ratably with the holders of other First Mortgage Bonds.

4.20    Ownership of Property. As of the Effective Date, each of the Borrower and its Significant Subsidiaries has good title to, or valid leasehold interests in, all its real and personal property material to its business, subject to no Liens other than Liens permitted under Section 7.3, except for where the failure would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

4.21    Covered Entity. The Borrower is not a Covered Entity.

4.22    Outbound Investment Rules. Neither the Borrower nor any of its Subsidiaries is a ‘covered foreign person’ as that term is used in the Outbound Investment Rules. Neither the Borrower nor any of its Subsidiaries currently engages, or has any present intention to engage in the future, directly or indirectly, in (a) a “covered activity” or a “covered transaction”, as each such term is defined in the Outbound Investment Rules, (b) any activity or transaction that would constitute a “covered activity” or a “covered transaction”, as each such term is defined in the Outbound Investment Rules, if the Borrower were a U.S. Person or (c) any other activity that would cause the Administrative Agent or any Lender to be in violation of the Outbound Investment Rules or cause the Administrative Agent or any Lender to be legally prohibited by the Outbound Investment Rules from performing under this Agreement.

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SECTION 5.    CONDITIONS PRECEDENT

5.1    Conditions to the Effective Date. The occurrence of the Effective Date and the obligation of each Lender to make its Loans hereunder on the Effective Date is subject to the satisfaction of the following conditions precedent:

(a)    Credit Agreement. The Administrative Agent shall have received this Agreement (including copies of all schedules attached hereto in a form reasonably satisfactory to the Lenders), executed and delivered by the Administrative Agent, the Borrower and each Person listed on Schedule 1.1.

(b)    Consents and Approvals. All governmental and third party consents and approvals necessary in connection with the execution and delivery of this Agreement and the other Loan Documents and the consummation of the transactions contemplated hereby shall have been obtained and be in full force and effect; and the Administrative Agent shall have received a certificate of a Responsible Officer to the foregoing effect.

(c)    KYC Information. At least three (3) Business Days prior to the Effective Date, the Administrative Agent and each Lender shall have received all documentation and information relating to the Borrower as is reasonably requested in writing by the Administrative Agent and/or any such Lender at least ten (10) Business Days prior to the Effective Date that is required by Governmental Authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation. If the Borrower qualifies as a “legal entity

customer” under the Beneficial Ownership Regulation and the Administrative Agent or any Lender so request at least five (5) Business Days prior to the Effective Date, then at least three (3) Business Days prior to the Effective Date, the Borrower shall have delivered to the Administrative Agent and/or any such Lender a Beneficial Ownership Certification in relation to the Borrower.

(d)    Bond Documents. The Administrative Agent shall have received:

(i)    the Bond Delivery Agreement, duly executed and delivered by the Borrower and Administrative Agent;

(ii)    the Senior Bond in a face amount equal to the Loans as of the Effective Date, duly issued and authenticated under the FMB Indenture and in a form reasonably satisfactory to the Administrative Agent;

(iii)    the Supplemental Indenture, duly executed and delivered by the Borrower and the Indenture Trustee and in a form reasonably satisfactory to the Administrative Agent;

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(iv)    a certificate of a duly authorized officer of the Indenture Trustee certifying that each Senior Bond has been authenticated and is outstanding under the FMB Indenture;

(v)    copies of all legal opinions and other documents delivered to the Indenture Trustee by or on behalf of the Borrower on or prior to the Effective Date in connection with the issuance of the Senior Bond; and

(vi)    copies of all title reports and commitments as of the Effective Date with respect to the Mortgaged Property consisting of real property as to which Liens in favor of the Indenture Trustee, for the benefit of the holders of the First Mortgage Bond, has been granted.

(e)    Fees. The Lenders and the Administrative Agent shall have received all fees required to be paid, and all expenses for which invoices have been presented (including the reasonable fees and expenses of legal counsel) on or before the date that is two (2) Business Days prior to the Effective Date.

(f)    Closing Certificate; Certified Articles of Incorporation; Good Standing Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated the Effective Date, substantially in the form of Exhibit D-1, with appropriate insertions and attachments, including the articles of incorporation of the Borrower certified as of a recent date by the Secretary of State of the State of California, (ii) a good standing certificate for the Borrower dated as of a recent date from the Secretary of State of the State of California, and (iii) a certificate of a Responsible Officer, dated the Effective Date, confirming the satisfaction of the conditions precedent set forth in Sections 5.1(h) and (i), substantially in the form of Exhibit D-2.

(g)    Legal Opinion. The Administrative Agent shall have received the legal opinion of Hunton Andrews Kurth LLP, counsel to the Borrower, in a form reasonably satisfactory to the Administrative Agent.

(h)    Representations and Warranties. Each of the representations and warranties made by the Borrower in this Agreement that does not contain a materiality qualification shall be true and correct in all material respects on and as of the Effective Date, and each of the representations and warranties made by the Borrower in this Agreement that contains a materiality qualification shall be true and correct on and as of the Effective Date (or, in each case, to the extent such representations and warranties specifically relate to an earlier date, that such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date).

(i)    No Default. No Default or Event of Default shall have occurred and be continuing on the Effective Date or would result from the funding of the Loans on the Effective Date.

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(j)    Notice of Borrowing. The Administrative Agent shall have received a notice of borrowing in accordance with the requirements of Section 2.2.

SECTION 6.    AFFIRMATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall and, with respect to Sections 6.3 and 6.6(b), shall cause its Significant Subsidiaries to:

6.1    Financial Statements. Furnish to the Administrative Agent with a copy for each Lender, and the Administrative Agent shall deliver to each Lender:

(a)    as soon as available, but in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such year and the related audited consolidated statements of income and cash flows for such year, setting forth in each case in comparative form the figures for the previous year, reported on without a “going concern” or like qualification or exception, or qualification arising out of the scope of the audit, by Deloitte & Touche LLP or other independent certified public accountants of nationally recognized standing; and

(b)    as soon as available, but in any event not later than 60 days after the end of each of the first three quarterly periods of each fiscal year of the Borrower, the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such quarter and the related unaudited consolidated statements of income and cash flows for such quarter and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year, certified by a Responsible Officer as being fairly stated in all material respects (subject to the absence of footnotes and normal year-end audit adjustments).

All such financial statements shall (x) be complete and correct in all material respects and (y) shall be prepared in reasonable detail and in accordance with GAAP applied (except as approved by such accountants or officer, as the case may be, and disclosed in reasonable detail therein) consistently throughout the periods reflected therein and with prior periods, subject, in each case to the absence of footnotes and to normal year-end audit adjustments. The Borrower shall be deemed to have delivered the financial statements required to be delivered pursuant to this Section 6.1 upon the filing of such financial statements by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or the publication by the Borrower of such financial statements on its website.

6.2    Certificates; Other Information. Furnish to the Administrative Agent, for delivery to the Lenders:

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(a)    within two Business Days after the delivery of any financial statements pursuant to Section 6.1, (i) a certificate of a Responsible Officer stating that such Responsible Officer has obtained no actual knowledge of any Default or Event of Default except as specified in such certificate and (ii) a Compliance Certificate, substantially in the form of Exhibit C, containing all information and calculations reasonably necessary for determining compliance by the Borrower with the provisions of this Agreement referred to therein as of the last day of the fiscal quarter or fiscal year of the Borrower, as the case may be;

(b)    within five days after the same are sent, copies of all financial statements and reports that the Borrower sends to the holders of any class of its debt securities or public equity securities, provided that, such financial statements and reports shall be deemed to have been delivered upon the filing of such financial statements and reports by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or publication by the Borrower of such financial statements and reports on its website;

(c)    promptly, such additional financial and other information (other than any such information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation) as any Lender, through the Administrative Agent, may from time to time reasonably request; and

(d)    promptly, such documentation and other information that the Administrative Agent or such Lender reasonably requests in order to comply with its

ongoing obligations under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation.

6.3    Payment of Taxes. Pay all taxes due and payable or any other tax assessments made against the Borrower or any of its Significant Subsidiaries or any of their respective property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable or (ii) where the failure to effect such payment could not reasonably be expected to have a Material Adverse Effect).

6.4    Maintenance of Existence; Compliance. (a)(i) Preserve, renew and keep in full force and effect its organizational existence and (ii) take all reasonable action to maintain all rights, privileges and franchises necessary or desirable in the normal conduct of its business, except, in each case, as otherwise permitted by Section 7.4 and except, in

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the case of clause (ii) above, to the extent that failure to do so could not reasonably be expected to have a Material Adverse Effect; (b) comply with all Contractual Obligations except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect and (c) comply with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings or except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

6.5    Maintenance of Property; Insurance. (a) Keep all property useful and necessary in its business in good working order and condition, ordinary wear and tear and casualty excepted, except to the extent that failure to do so could not, in the aggregate, reasonably be expected to have a Material Adverse Effect, and (b) maintain with financially sound and reputable insurance companies insurance on all its material property in at least such amounts and against at least such risks as are usually insured against in the same general area by companies engaged in the same or a similar business of comparable size and financial strength and owning similar properties in the same general areas in which the Borrower operates, which may include self-insurance, if determined by the Borrower to be reasonably prudent.

6.6    Inspection of Property; Books and Records; Discussions. (a) Keep proper books of records and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law shall be made of all dealings and transactions in relation to its business and activities and (b) unless a Default or Event of Default has occurred and is continuing, not more than once a year and after at least five Business Days’ notice, (i) permit representatives of any Lender to visit and inspect any of its properties and examine and make abstracts from any of its books and records at any reasonable time to discuss the business, operations, properties and financial and other condition of the Borrower and its Significant Subsidiaries with officers and employees of the Borrower and its Significant Subsidiaries and (ii) use commercially reasonable efforts to provide for the Lenders (in the presence of representatives of the Borrower) to meet with the independent certified public accountants of the Borrower and its Significant Subsidiaries; provided, that any such visits or inspections shall be subject to such conditions as the Borrower and each of its Significant Subsidiaries shall deem necessary based on reasonable considerations of safety, security and confidentiality; and provided, further, that neither the Borrower nor any Significant Subsidiary shall be required to disclose to any Person any information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation.

6.7    Notices. Give notice to the Administrative Agent, and the Administrative Agent shall deliver such notice to each Lender, promptly upon any Responsible Officer obtaining knowledge of:

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(a)    the occurrence of any Default or Event of Default;

(b)    [reserved]; and

(c)    the occurrence of an ERISA Event which, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect (provided, that, any judicial proceeding instituted by PBGC that, within 60 days after the institution of such proceeding, has been withdrawn or stayed by PBGC or otherwise, shall be disregarded for the purpose of this Section 6.7(c)).

6.8    Maintenance of Licenses, etc. Maintain in full force and effect any authorization, consent, license or approval of any Governmental Authority necessary for the conduct of the Borrower’s business as now conducted by it or necessary in connection with this Agreement, except to the extent the failure to do so could not reasonably be expected to have a Material Adverse Effect.

6.9    Further Assurances.

(a)    (i) Comply with Section 7.08(a) of the FMB Indenture, (ii) deliver to the Administrative Agent within 120 days after the Effective Date, a copy of the Opinion of Counsel (as defined in the FMB Indenture) delivered to the Indenture Trustee under Section 7.08(a)(i) of the FMB Indenture relating the Supplemental Indenture and (iii) deliver to the Administrative Agent a copy of each Opinion of Counsel delivered to the Indenture Trustee under Section 7.08(a)(ii) of the FMB Indenture relating to the Supplemental Indenture.

(b)    Promptly upon the reasonable request by the Administrative Agent, or by the Required Lenders through the Administrative Agent, (i) correct any material defect or error that may be discovered in any Loan Document or the execution, acknowledgment, filing or recordation thereof and (ii) do, execute, acknowledge and deliver any and all such further certificates, documents, agreements and other instruments as reasonably

required from time to time to carry out more effectively the purposes of the Loan Documents.

6.10    Use of Proceeds. The Borrower shall use the proceeds of the Loans in accordance with Section 4.12.

SECTION 7.    NEGATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, or any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall not and shall not permit its Significant Subsidiaries to:

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7.1    [Reserved].

7.2    Consolidated Capitalization Ratio. Permit the Consolidated Capitalization Ratio on the last day of any fiscal quarter, from and after the last day of the first fiscal quarter ending after the Effective Date, to exceed 0.65 to 1.00.

7.3    Liens. Create, incur, assume or suffer to exist any Lien upon any assets of the Borrower or any Significant Subsidiary, whether now owned or hereafter acquired, except for (a) Liens securing the Obligations under this Agreement and the other Loan Documents and (b) Liens permitted under Section 7.06(b) of the FMB Indenture.

7.4    Fundamental Changes. Enter into any merger, consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of all or substantially all of its property or business (including, without limitation, rental equipment or leasehold interests and excluding the sale or transfer of any accounts receivable or of any amounts that are accrued and recorded in a regulatory account for collections by the Borrower, in each case, in connection with a securitization transaction including, without limitation, any A/R Securitization Transaction), except that the Borrower may be merged, consolidated or amalgamated with another Person or Dispose of all or substantially all of its property or business so long as, after giving effect to such transaction, (a) no Default or Event of Default shall have occurred and be continuing, (b) either (i) the Borrower is the continuing or surviving corporation of such merger, consolidation or amalgamation or (ii) the continuing or surviving corporation of such merger, consolidation or amalgamation, if not the Borrower or the purchaser, (x) shall be an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia, (y) shall have assumed all obligations of the Borrower under the Loan Documents pursuant to arrangements reasonably satisfactory to the Administrative Agent and (z) to the extent requested by the Administrative Agent or any Lender, shall have promptly provided to the Administrative Agent or such Lender all documentation and other information that may be required by the Administrative Agent or such Lender in order to enable compliance with applicable “know-your-customer” and anti-money laundering rules and regulations, including information required by the Patriot Act and the Beneficial Ownership Regulation and (c)

the ratings by Moody’s and S&P of the continuing or surviving corporation’s or purchaser’s senior, secured debt shall be at least the higher of (1) Baa3 from Moody’s and BBB- from S&P and (2) the ratings by such rating agencies of the Borrower’s senior, secured debt in effect before the earlier of the occurrence or the public announcement of such event.

7.5    Sale and Lease Back Transactions. Enter into any arrangement, directly or indirectly, with any Person whereby it shall sell or transfer any property having fair market value in excess of $10,000,000, real or personal, used or useful in its business, whether now owned or hereafter acquired, and thereafter rent or lease such property or other property that it intends to use for substantially the same purpose or purposes as the

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property being sold or transferred, except for (a) those transactions described on Schedule 7.5 and (b) any other sale of any fixed or capital assets that is made for cash consideration; provided that, in each case, if such sale and leaseback results in a Capital Lease Obligation, any Lien made the subject of such Capital Lease Obligation is permitted by Section 7.3.

7.6    Swap Agreements. Enter into any Swap Agreement, other than Swap Agreements entered into not for speculative purposes (a) to hedge or mitigate risks to which the Borrower and its Subsidiaries are exposed in the conduct of its business or the management of its liabilities (including, without limitation, raw material, commodities, fuel, electricity or other supply costs and currency risks), (b) to effectively cap, collar or exchange interest rates (from fixed to floating rates, from one floating rate to another floating rate or fixed rate or otherwise) with respect to any interest bearing Indebtedness of the Borrower and its Subsidiaries permitted by this Agreement, (c) to swap currency in connection with funding the business of the Borrower and its Subsidiaries in the ordinary course of business or (d) entered into in connection with any A/R Securitization Transaction.

7.7    Amendments to FMB Indenture. Amend, supplement, modify or waive the FMB Indenture in any manner that is materially adverse to the Lenders hereunder; provided that the foregoing shall not prohibit the Borrower from supplementing the FMB Indenture in order to provide for the issuance of additional First Mortgage Bonds in accordance with the FMB Indenture or to add property to the Lien of the FMB Indenture.

7.8    Outbound Investment Rules. The Borrower will not, and will not permit any of its Subsidiaries to, (a) be or become a “covered foreign person”, as that term is defined in the Outbound Investment Rules, or (b) engage, directly or indirectly, in (i) a “covered activity” or a “covered transaction”, as each such term is defined in the Outbound Investment Rules, (ii) any activity or transaction that would constitute a “covered activity” or a “covered transaction”, as each such term is defined in the Outbound Investment Rules, if the Borrower were a U.S. Person or (iii) any other activity that would cause the Administrative Agent or any Lender to be in violation of the Outbound Investment Rules or cause the Administrative Agent or any Lender to be legally prohibited by the Outbound Investment Rules from performing under this Agreement.

SECTION 8.    EVENTS OF DEFAULT

If any of the following events shall occur and be continuing on or after the Effective Date:

(a)    the Borrower shall fail to pay any principal of the Loans when due in accordance with the terms hereof; or the Borrower shall fail to pay any interest on the Loans, or any other amount payable hereunder or under any other Loan Document, within five Business Days after any such interest or other amount becomes due in accordance with the terms hereof; or

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(b)    any representation or warranty made or deemed made by the Borrower herein or in any other Loan Document or that is contained in any certificate, document or financial or other statement furnished by it at any time under or in connection with this Agreement or any such other Loan Document shall prove to have been inaccurate in any material respect on or as of the date made or deemed made, unless, as of any date of determination, the facts or circumstances to which such representation or warranty relates have changed with the result that such representation or warranty is true and correct in all material respects on such date; or

(c)    the Borrower shall default in the observance or performance of any agreement contained in Section 6.4(a)(i), Section 6.7(a), Section 6.10, Section 7.2, Section 7.3 or Section 7.4 of this Agreement; or

(d)    the Borrower shall default in the observance or performance of any other agreement contained in this Agreement or any other Loan Document (other than as provided in paragraphs (a) through (c) of this Section), and such default shall continue unremedied for a period of 30 days after notice to the Borrower from the Administrative Agent at the request of the Required Lenders; or

(e)    the Borrower or any of its Significant Subsidiaries shall (i) default in making any payment of any principal of any Indebtedness (including any Guarantee Obligation, but excluding the Loans) on the due date with respect thereto (after giving effect to any period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created); or (ii) default in making any payment of any interest on any such Indebtedness beyond the period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created; or (iii) default in the observance or performance of any other agreement or condition relating to any such Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event shall occur or condition exist, the effect of which default or other event or condition is to cause, or (in the case of all Indebtedness other than Indebtedness under any Swap Agreement) to permit the holder or beneficiary of such Indebtedness (or a trustee or agent on behalf of such holder or beneficiary) to cause, with the giving of notice if required, such Indebtedness to become due prior to its stated maturity or (in the case of any such Indebtedness constituting a Guarantee Obligation) to become payable; provided, that a default, event or condition described in clause (i), (ii) or (iii) of this paragraph (e) shall not at any time constitute an Event of Default unless, at such time, one

or more defaults, events or conditions of the type described in clauses (i), (ii) and (iii) of this paragraph (e) shall have occurred and be continuing with respect to Indebtedness the outstanding principal amount of which exceeds in the aggregate $200,000,000; provided, further, that unless payment of the Loans hereunder has already been accelerated, if such default shall be cured by the Borrower or such Significant Subsidiary or waived by the holders of such Indebtedness and any acceleration of maturity having resulted from such default shall be rescinded or annulled, in each case, in accordance with the terms of such agreement or instrument, without any modification of the terms of such Indebtedness requiring the Borrower or such Significant Subsidiary to furnish security or additional

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security therefor, reducing the average life to maturity thereof or increasing the principal amount thereof, or any agreement by the Borrower or such Significant Subsidiary to furnish security or additional security therefor or to issue in lieu thereof Indebtedness secured by additional or other collateral or with a shorter average life to maturity or in a greater principal amount, then any Default hereunder by reason thereof shall be deemed likewise to have been thereupon cured or waived; or

(f)    (i) the Borrower or any of its Significant Subsidiaries shall commence any case, proceeding or other action (A) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, reorganization or relief of debtors, seeking to have an order for relief entered with respect to it, or seeking to adjudicate it as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding up, liquidation, dissolution, composition or other relief with respect to it or its debts, or (B) seeking appointment of a receiver, trustee, custodian, conservator or other similar official for it or for all or any substantial part of its assets, or the Borrower or any of its Significant Subsidiaries shall make a general assignment for the benefit of its creditors; or (ii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action of a nature referred to in clause (i) above that (A) results in the entry of an order for relief or any such adjudication or appointment or (B) remains undismissed, undischarged or unbonded for a period of 60 days; or (iii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action seeking issuance of a warrant of attachment, execution, distraint or similar process against all or any substantial part of its assets that results in the entry of an order for any such relief that shall not have been vacated, discharged, or stayed or bonded pending appeal within 60 days from the entry thereof; or (iv) the Borrower or any of its Significant Subsidiaries shall generally not, or shall be unable to, or shall admit in writing its inability to, pay its debts as they become due; or

(g)    there occurs any ERISA Event that, individually or in the aggregate, would reasonably be expected to result in a Material Adverse Effect; or

(h)    one or more judgments or decrees shall be entered against the Borrower or any of its Significant Subsidiaries by a court of competent jurisdiction involving in the aggregate a liability (not paid or, subject to customary deductibles, fully covered by insurance as to which the relevant insurance company has not denied coverage) of $200,000,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 45 days from the entry thereof

unless, in the case of a discharge, such judgment or decree is due at a later date in one or more payments and the Borrower or such Significant Subsidiary satisfies the obligation to make such payment or payments on or prior to the date such payment or payments become due in accordance with such judgment or decree; or

(i)    there shall have occurred a Change of Control; or

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(j)    any Loan Document, at any time after its execution and delivery and for any reason other than as expressly permitted hereunder or thereunder or satisfaction in full of all the Obligations, ceases to be in full force and effect; or the Borrower contests in any manner in writing the validity or enforceability of any Loan Document; or the Borrower denies in writing that it has any or further liability or obligation under any Loan Document, or purports in writing to revoke, terminate or rescind any Loan Document; or

(k)    at any time (i) the Senior Bond shall cease to be outstanding for any reason other than (A) the payment in full of the applicable Tranche relating to such Senior Bond and other obligations then due and owing under the Loan Documents with respect thereto or (B) the payment in full of such Senior Bond, (ii) the Administrative Agent, on behalf of the Lenders, shall cease at any time to be the holder of the Senior Bond for all purposes of the FMB Indenture (unless such Senior Bond is transferred by the Administrative Agent other than in connection with the payment in full of the obligations with respect to such Senior Bond) or (iii) the Lien of the FMB Indenture shall cease to constitute a valid and enforceable Lien on the Mortgaged Property;

then, and in any such event, (A) if such event is an Event of Default specified in clause (i) or (ii) of paragraph (f) above with respect to the Borrower, the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents shall immediately become due and payable, and (B) if such event is any other Event of Default, either or both of the following actions may be taken: with the consent of the Required Lenders, the Administrative Agent may, or upon the request of the Required Lenders, the Administrative Agent shall, by notice to the Borrower, declare the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents to be due and payable forthwith, whereupon the same shall immediately become due and payable. Except as expressly provided above in this Section, presentment, demand, protest and all other notices of any kind are hereby expressly waived by the Borrower.

SECTION 9.    THE AGENTS

9.1    Appointment and Authority. Each of the Lenders hereby irrevocably appoints Bank of America, N.A. to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Section 9 are solely for the benefit of the Agents, the Lenders and the Borrower shall not have rights as a third-party beneficiary of any of such provisions (other than with respect to the

Borrower’s rights under Sections 9.9(a) and (b)). It is understood and agreed that the use of the term “agent” herein or in any other Loan Documents (or any other similar term) with reference to any Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law. Instead such

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term is used as a matter of market custom, and is intended to create or reflect only an administrative relationship between contracting parties.

9.2    Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by it. The Administrative Agent, and any such sub-agent may each perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Section shall apply to any such sub-agent and to the Related Parties of the Administrative Agent, and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent. The Administrative Agent shall not be responsible for the negligence or misconduct of any sub-agents except to the extent that a court of competent jurisdiction determines in a final and nonappealable judgment that the Administrative Agent acted with gross negligence or willful misconduct in the selection of such sub-agents.

9.3    Exculpatory Provisions.

(a)    No Agent shall have any duties or obligations except those expressly set forth herein and in the other Loan Documents, and its duties hereunder shall be administrative in nature. Without limiting the generality of the foregoing, no Agent:

(i)    shall be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

(ii)    shall have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that an Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents); provided that no Agent shall be required to take any action that, in its opinion or the opinion of its counsel, may expose such Agent to liability or that is contrary to any Loan Document or applicable law, including for the avoidance of doubt any action that may be in violation of the automatic stay under any Debtor Relief Law or that may effect a forfeiture, modification or termination of property of a Defaulting Lender in violation of any Debtor Relief Law; and

(iii)    shall, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is

communicated to or obtained by the Person serving as an Agent or any of its Affiliates in any capacity.

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(b)    No Agent shall be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as such Agent shall believe in good faith shall be necessary, under the circumstances as provided in Sections 10 and 8), or (ii) in the absence of its own gross negligence or willful misconduct as determined by a court of competent jurisdiction by final and nonappealable judgment.

(c)    No Agent shall be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default or Event of Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Section 5 or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to such Agent.

9.4    Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan, that by its terms must be fulfilled to the satisfaction of a Lender, the Administrative Agent may presume that such condition is satisfactory to such Lender unless the Administrative Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

9.5    Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default unless the Administrative Agent has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Required Lenders (or, if so specified by this Agreement, all Lenders); provided that unless and until such Agent shall have received such directions, such Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.

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9.6    Non-Reliance on Agents and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, property, condition (financial or otherwise), prospects or creditworthiness of the Borrower or any of its Affiliates that may come into the possession of such Agent or any of its officers, directors, employees, agents, attorneys in fact or Affiliates.

9.7    Indemnification. The Lenders agree to indemnify each Agent in its capacity as such (to the extent not reimbursed by the Borrower and without limiting the obligation of the Borrower to do so), ratably according to their respective Percentages in effect on the date on which indemnification is sought under this Section (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with such Percentages immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time (whether before or after the payment of the Loans) be imposed on, incurred by or asserted against such Agent in any way relating to or arising out of, the Commitments, this Agreement, any of the other Loan Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from such Agent’s gross negligence or willful misconduct.

9.8    Agent in Its Individual Capacity. Each Person serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and the terms “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include such Person serving as an Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, own securities of, act as the financial advisor or in any other advisory capacity for, and generally engage in any kind of business with, the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not an Agent hereunder and without any duty to account therefor to the Lenders.

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9.9    Successor Agents.

(a)    The Administrative Agent may resign upon 10 days’ notice to the Lenders and the Borrower. If the Administrative Agent shall so resign under this Agreement and the other Loan Documents, then the Required Lenders shall appoint from among the Lenders a successor agent for the Lenders, which successor agent shall (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing) be subject to approval by the Borrower (which approval shall not be unreasonably withheld, conditioned or delayed), whereupon such successor agent shall succeed to the rights, powers and duties of the Administrative Agent and the term “Administrative Agent” shall mean such successor agent effective upon such appointment and approval, and the former Agent’s rights, powers and duties as Administrative Agent shall be terminated, without any other or further act or deed on the part of such former Agent or any of the parties to this Agreement or any holders of the Loans. If no successor agent has accepted appointment as Administrative Agent by the date that is 10 days following a retiring Agent’s notice of resignation (the “Resignation Effective Date”), the retiring Agent’s resignation shall nevertheless thereupon become effective, and the Lenders shall assume and perform all of the duties of the Administrative Agent hereunder until such time, if any, as the Required Lenders appoint a successor agent as provided for above. After any retiring Agent’s resignation as Administrative Agent the provisions of Section 9.7 shall inure to its benefit as to any actions taken or omitted to be taken by it while it was an Agent under this Agreement and the other Loan Documents.

(b)    If the Person serving as Administrative Agent is a Defaulting Lender pursuant to clause (e) of the definition thereof, the Required Lenders may, to the extent permitted by applicable law, by notice in writing to the Borrower and such Person remove such Person as Administrative Agent and, shall appoint a successor, subject to the approval of the Borrower (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing), which approval shall not be unreasonably withheld, conditioned or delayed. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days (or such earlier day as shall be agreed by the Required Lenders) (the “Removal Effective Date”), then such removal shall nonetheless become effective in accordance with such notice on the Removal Effective Date.

(c)    With effect from the Resignation Effective Date or the Removal Effective Date (as applicable) (i) the retiring or removed Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of the Senior Bond held by the Administrative Agent on behalf of the Lenders, the retiring or removed Administrative Agent shall continue to hold such Senior Bond in its name until such time as a successor Administrative Agent is appointed) and (ii) except for any indemnity payments or other amounts then owed to the retiring or removed Administrative Agent, all payments, communications and determinations provided to be

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made by, to or through the Administrative Agent shall instead be made by or to each Lender directly, until such time, if any, as the Required Lenders appoint a successor Administrative Agent as provided for above. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring or removed Agent (other than any rights to indemnity payments or other amounts owed to the retiring or removed Agent as of the Resignation Effective Date or the Removal Effective Date (as applicable)), and the retiring or removed Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring or removed Agent’s resignation or removal hereunder and under the other Loan Documents, the provisions of this Section and Sections 2.17 and 10.5 shall continue in effect for the benefit of such retiring or removed Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring or removed Agent was acting as Agent.

9.10    Reserved.

9.11    Administrative Agent May File Proofs of Claim. In case of the pendency of any proceeding under any Debtor Relief Law, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered (but not obligated) by intervention in such proceeding or otherwise:

(a)    to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Obligations that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Sections 2.6, 2.17 and 10.5) allowed in such judicial proceeding; and

(b)    to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

(c)    and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its

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agents and counsel, and any other amounts due to the Administrative Agent under Sections 2.6, 2.17 and 10.5.

9.12    Certain ERISA Matters.

(a)    Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

(i)    such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA or otherwise) of one or more Benefit Plans with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments or this Agreement,

(ii)    the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement,

(iii)    (A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement, or

(iv)    such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(b)    In addition, unless either (1) sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or (2) a Lender has provided another representation, warranty and covenant in accordance with sub-clause (iv) in the

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immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of

doubt, to or for the benefit of the Borrower, that the Administrative Agent is not a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related hereto or thereto).

9.13    Erroneous Payment.

(a)    If the Administrative Agent notifies a Lender or any Person who has received funds on behalf of a Lender (any such Lender or other recipient, a “Payment Recipient”) that the Administrative Agent has determined in its sole discretion (whether or not after receipt of any notice under immediately succeeding clause (b)) that any funds received by such Payment Recipient from the Administrative Agent or any of its Affiliates were erroneously transmitted to, or otherwise erroneously or mistakenly received by, such Payment Recipient (whether or not known to such Lender or other Payment Recipient on its behalf) (any such funds, whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise, individually and collectively, an “Erroneous Payment”) and demands the return of such Erroneous Payment (or a portion thereof), such Erroneous Payment shall at all times remain the property of the Administrative Agent and shall be segregated by the Payment Recipient and held in trust for the benefit of the Administrative Agent, and such Lender shall (or, with respect to any Payment Recipient who received such funds on its behalf, shall cause such Payment Recipient to) promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such Erroneous Payment (or portion thereof) as to which such a demand was made, in same day funds (in the currency so received), together with interest thereon in respect of each day from and including the date such Erroneous Payment (or portion thereof) was received by such Payment Recipient to the date such amount is repaid to the Administrative Agent in same day funds at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect. A notice of the Administrative Agent to any Payment Recipient under this clause (a) shall be conclusive, absent manifest error.

(b)    Without limiting immediately preceding clause (a), each Lender or other Payment Recipient hereby further agrees that if it receives a payment, prepayment or repayment (whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise) from the Administrative Agent (or any of its Affiliates) (x) that is in a different amount than, or on a different date from, that specified in a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment, prepayment or repayment, (y) that was

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not preceded or accompanied by a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates), or (z) that such Lender, or other such recipient, otherwise becomes aware was transmitted, or received, in error or by mistake (in whole or in part) in each case:

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(i)    (A) in the case of immediately preceding clauses (x) or (y), an error shall be presumed to have been made (absent written confirmation from the Administrative Agent to the contrary) or (B) an error has been made (in the case of immediately preceding clause (z)), in each case, with respect to such payment, prepayment or repayment; and

(ii)    such Lender shall (and shall cause any other recipient that receives funds on its respective behalf to) promptly (and, in all events, within one Business Day of its knowledge of such error) notify the Administrative Agent of its receipt of such payment, prepayment or repayment, the details thereof (in reasonable detail) and that it is so notifying the Administrative Agent pursuant to this Section 9.13(b), and upon demand from the Administrative Agent, it shall promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such payment, prepayment or repayment as to which such a demand was made in same day funds, together with interest thereon in respect of each day from and including the date such payment, prepayment or repayment was received by such Lender to the date such amount is repaid to the Administrative Agent at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect.

(c)    Each Lender hereby authorizes the Administrative Agent to set off, net and apply any and all amounts at any time owing to such Lender under any Loan Document, or otherwise payable or distributable by the Administrative Agent to such Lender from any source, against any amount due to the Administrative Agent under immediately preceding clause (a) or under the indemnification provisions of this Agreement.

(d)    The Borrower hereby agrees that in the event an Erroneous Payment (or portion thereof) are not recovered from any Lender that has received such Erroneous Payment (or portion thereof) for any reason, the Administrative Agent shall be subrogated to all the rights of such Lender with respect to such amount.

(e)    The parties hereto agree that an Erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower, except, in each case, to the extent such Erroneous Payment is, and solely with respect to the amount of such Erroneous Payment that is, comprised of funds received by the Administrative Agent from the Borrower for the purpose of making such Erroneous Payment.

(f)    To the extent permitted by applicable law, no Payment Recipient shall assert any right or claim to an Erroneous Payment, and hereby waives, and is deemed to waive, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the Administrative Agent for the return of any Erroneous Payment received, including without limitation waiver of any defense based on “discharge for value” or any similar doctrine.

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(g)    Each party’s obligations, agreements and waivers under this Section 9.13 shall survive the resignation or replacement of the Administrative Agent, any transfer of rights or obligations by, or the replacement of a Lender, the termination of the Commitments and/or the repayment, satisfaction or discharge of all Obligations (or any portion thereof) under any Loan Document.

SECTION 10.    MISCELLANEOUS

10.1    Amendments and Waivers. Subject to Section 2.13(b) and (c), neither this Agreement, any other Loan Document, nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this Section 10. The Required Lenders and the Borrower may, or, with the written consent of the Required Lenders, the Administrative Agent and the Borrower may, from time to time, (a) enter into written amendments, supplements or modifications hereto and to the other Loan Documents for the purpose of adding any provisions to this Agreement or the other Loan Documents or changing in any manner the rights of the Lenders or of the Borrower hereunder or thereunder or (b) waive, on such terms and conditions as the Required Lenders or the Administrative Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Loan Documents or any Default or Event of Default and its consequences; provided, however, that no such waiver and no such amendment, supplement or modification shall:

(i)    forgive the principal amount or extend the final scheduled date of maturity of any Loan, reduce the stated rate of any interest or fee payable hereunder (except in connection with the waiver of applicability of any post-default increase in interest rates (which waiver shall be effective with the consent of the Required Lenders)) or extend the scheduled date of any payment thereof, in each case without the written consent of each Lender directly affected thereby;

(ii)    eliminate or reduce the voting rights of any Lender under this Section 10 or Section 10.6(a)(i) without the written consent of such Lender;

(iii)    reduce any percentage specified in the definition of Required Lenders without the written consent of all Lenders;

(iv)    amend, modify or waive any provision of Section 2.14, Section 10.7 (Application of Money Collected) of the FMB Indenture or any similar provision in the Loan Documents related to pro rata treatment without the consent of each Lender directly affected thereby;

(v)    amend, modify or waive any provision of Section 9 without the written consent of the Administrative Agent;

(vi)    [reserved];

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(vii)    amend, modify or waive any provision of Section 5 without the written consent of all the Lenders;

(viii)    amend, modify or waive any provision of Section 2.8 without the written consent of each Lender affected thereby;

(ix)    amend or modify any provision in any Loan Document in a manner that by its terms affects the rights or duties under this Agreement of the Lenders of one Tranche (but not the other Tranche), without the prior written consent of the requisite number or percentage in interest of each affected Tranche of Lenders that would be required to consent thereto under this Section if such Tranche of Lenders were the only Tranche of Lenders hereunder at the time; or

(x)    instruct the Administrative Agent to vote the Senior Bond in favor of the release of all or substantially all of the Mortgaged Property without the written consent of all the Lenders.

Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Lenders and shall be binding upon the Borrower, the Lenders, the Administrative Agent and all future holders of the Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; but no such waiver shall extend to any subsequent or other Default or Event of Default, or impair any right consequent thereon.

Notwithstanding anything to the contrary contained in this Section 10, if the Administrative Agent and the Borrower acting together identify any ambiguity, omission, mistake, typographical error or other defect in any provision of this Agreement or any other Loan Document, then the Administrative Agent and the Borrower shall be permitted to amend, modify or supplement such provision to cure such ambiguity, omission, mistake, typographical error or other defect, and any such amendment, modification or supplement shall become effective without any further action or consent of any other party to this Agreement.

If the Required Lenders shall have approved any amendment which requires the consent of all of the Lenders, the Borrower shall be permitted to replace any non-consenting Lender with another financial institution, provided that, (i) the replacement financial institution shall purchase at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (ii) the Borrower shall be liable to such replaced Lender under Section 2.17 if any Term Benchmark Loan owing to such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto (as if such purchase constituted a prepayment of such Loans), (iii) such replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (iv) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the

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Borrower shall be obligated to pay the registration and processing fee referred to therein)

(for the avoidance of doubt, such replacement shall be effective subject to the conditions in the other clauses set forth in this proviso, regardless of whether such replaced Lender enters into an Assignment and Assumption) and (v) any such replacement shall not be deemed to be a waiver of any rights the Borrower, the Administrative Agent, or any other Lender shall have against the replaced Lender.

Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, supplement, modification, waiver or consent hereunder (and any amendment, supplement, modification, waiver or consent which by its terms requires the consent of all Lenders or each affected Lender may be effected with the consent of the applicable Lenders other than Defaulting Lenders), except that (i) any reduction of the amount of principal or interest owed to such Defaulting Lender shall, in each case, require the consent of such Defaulting Lender, and (ii) a Defaulting Lender’s Percentage shall be taken into consideration along with the Percentage of non-Defaulting Lenders when voting to approve or disapprove any waiver, amendment or modification that by its terms affects any Defaulting Lender more adversely than other affected Lenders.

10.2    Notices.

(a)    All notices, requests and demands to or upon the respective parties hereto to be effective shall be in writing (including by telecopy), and, unless otherwise expressly provided herein, shall be deemed to have been duly given or made when delivered during the recipient’s normal business hours, or, if mailed by certified or registered mail, shall be deemed to have been given when received, or, in the case of telecopy notice, when received during the recipient’s normal business hours, addressed as follows in the case of the Borrower and the Administrative Agent, and as set forth in an administrative questionnaire delivered to the Administrative Agent in the case of the Lenders, or to such other address as may be hereafter notified by the respective parties hereto in accordance with clause (e) or clause (f) of this Section 10.2:

Borrower:    Pacific Gas and Electric Company c/o PG&E Corporation 300 Lakeside Drive Oakland, California 94612 Attention: Treasurer Telecopy: (415) 973-8968 Telephone: (415) 973-8956

with a copy to:    Pacific Gas and Electric Company c/o PG&E Corporation 300 Lakeside Drive Oakland, California 94612

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Attention: General Counsel Telecopy: (415) 973-5520

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Administrative Agent:    Bank of America, N.A. 900 W Trade Street Charlotte, NC 28255-0001 Mail Code: NC1-026-06-04 Attention: Libby Russell Telephone: (980) 386-8451 Email: libby.russell@bofa.com

with a copy to:    Email: eCredit_Dedicated@bofa.com

provided that any notice, request or demand to or upon the Administrative Agent or any Lender shall not be effective until received.

(b)    Notices and other communications to the Administrative Agent or the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices to any Lender pursuant to Section 2 unless otherwise agreed by such Lender. Notices to the Administrative Agent pursuant to Section 2 may be transmitted to the Administrative Agent by electronic/soft medium in a format reasonably acceptable to the Administrative Agent to eCredit_Dedicated@bofa.com. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c)    Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient, at its e-mail address as described in the foregoing clause (i), of notification that such notice or communication is available and identifying the website address therefor; provided that, for both clauses (i) and (ii) above, if such notice, email or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient.

(d)    The Borrower agrees that the Administrative Agent may, but shall not be obligated to, make the Communications (as defined below) available to the Lenders by posting the Communications on Debt Domain, Intralinks, Syndtrak or a substantially similar electronic transmission system (the “Platform”).

(i)    The Platform is provided “as is” and “as available.” The Agent Parties (as defined below) do not warrant the adequacy of the Platform and expressly disclaim liability for errors or omissions in the Communications. No

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warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by any Agent Party in connection with the Communications or the Platform. In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to the Borrower, any Lender or any other Person or entity for damages of any kind, including, without limitation, direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of the Borrower’s or the Administrative Agent’s transmission of Communications through the Platform, except to the extent such liability resulted from the gross negligence or willful misconduct of the Administrative Agent or any of its Related Parties as determined by a court of competent jurisdiction in a final non-appealable judgment. “Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of the Borrower pursuant to any Loan Document or the transactions contemplated therein which is distributed to the Administrative Agent or any Lender by means of electronic communications pursuant to this Section, including through the Platform.

(e)    Each of the Borrower and the Administrative Agent may change its address, facsimile or telephone number for notices and other communications hereunder by notice to the other parties hereto. Each Lender may change its address, facsimile or telephone number for notices and other communications hereunder by notice to the Administrative Agent.

(f)    The Administrative Agent and the Lenders shall be entitled to rely and act upon any notices (including telephonic notices and notices requesting a Borrowing or a conversion or continuation of Loans) purportedly given by or on behalf of the Borrower even if (i) such notices were not made in a manner specified herein, were incomplete or were not preceded or followed by any other form of notice specified herein, or (ii) the terms thereof, as understood by the recipient, varied from any confirmation thereof.

10.3    No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of the Administrative Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Loan Documents shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.

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10.4    Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Loan Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

10.5    Payment of Expenses and Taxes. The Borrower agrees (a) to pay or reimburse the Administrative Agent and the Lenders for all their respective reasonable out of pocket costs and expenses incurred in connection with the development, preparation and execution of, and any amendment, supplement or modification to, this Agreement and the other Loan Documents and any other documents prepared in connection herewith or therewith, and the consummation of the transactions contemplated hereby and thereby, including the reasonable fees and disbursements of only one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons) and filing and recording fees and expenses, with statements with respect to the foregoing to be submitted to the Borrower prior to the Effective Date (in the case of amounts to be paid on the Effective Date) and from time to time thereafter on a quarterly basis or such other periodic basis as the Administrative Agent shall deem appropriate, (b) to pay or reimburse each Lender and the Administrative Agent for all its costs and expenses incurred in connection with the enforcement or preservation of its rights under this Agreement, the other Loan Documents and any such other documents, including the reasonable fees and disbursements of only one joint counsel, one joint special California counsel and, if necessary, one local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), and (c) to pay, indemnify, and hold each Lender, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and agents (each, an “Indemnitee”) harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever whether brought by the Borrower or any other Person, with respect to the execution, delivery, enforcement and performance of, or arising out of or in connection with, this Agreement, the other Loan Documents and any such other documents, including any of the foregoing relating to the use of proceeds of the Loans or the violation of, noncompliance with or liability under, any Environmental Law directly or indirectly relating to the Borrower, its Significant Subsidiaries or any of the facilities and properties owned, leased or operated by the Borrower or its Significant Subsidiaries and the reasonable, documented and invoiced fees and expenses of one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the applicable Indemnitee (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), in connection with claims, actions or proceedings by any Indemnitee against the Borrower under any Loan Document (all the foregoing in this clause (c), collectively, the “Indemnified Liabilities”), provided, that the Borrower shall have no

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obligation hereunder to any Indemnitee with respect to Indemnified Liabilities to the extent such Indemnified Liabilities resulted from, as determined in a final non-appealable judgment by a court of competent jurisdiction, (x) the gross negligence, bad faith or willful misconduct of such Indemnitee or its Affiliates, (y) the material breach of such Indemnitee’s funding obligations hereunder or (z) a dispute amongst one or more Lenders

not arising from the Borrower’s breach of its obligations under the Loan Documents (other than a dispute involving a claim against an Indemnitee for its acts or omissions in its capacity as an arranger, bookrunner, agent or similar role in respect of the Loan Agreement, except, to the extent such acts or omissions are determined by a court of competent jurisdiction by a final and non-appealable judgment to have constituted the gross negligence, bad faith or willful misconduct of such Indemnitee in such capacity). Without limiting the foregoing, and to the extent permitted by applicable law, the Borrower agrees not to assert and to cause its Significant Subsidiaries not to assert, and hereby waives and agrees to cause its Significant Subsidiaries to waive, all rights for contribution or any other rights of recovery with respect to all claims, demands, penalties, fines, liabilities, settlements, damages, costs and expenses of whatever kind or nature, under or related to Environmental Laws, that any of them might have by statute or otherwise against any Indemnitee. All amounts due under this Section 10.5 shall be payable not later than 30 days after written demand therefor, subject to the Borrower’s receipt of reasonably detailed invoices. Statements payable by the Borrower pursuant to this Section 10.5 shall be submitted to Treasurer (Telephone No. (415) 817-8199/(415) 267-7000) (Telecopy No. (415) 267-7265/7268), at the address of the Borrower set forth in Section 10.2(a) with a copy to Chief Counsel, Corporate (Telephone No. (415) 817-8200) (Telecopy No. (415) 817-8225), at the address of the Borrower set forth in Section 10.2(a), or to such other Person or address as may be hereafter designated by the Borrower in a written notice to the Administrative Agent. The agreements in this Section 10.5 shall survive for two years after repayment of the Loans and all other amounts payable hereunder. This Section 10.5 shall not apply with respect to Taxes, other than Taxes that represent claims, damages, losses, liabilities, costs or expenses arising from non-Tax claims.

10.6    Successors and Assigns; Participations and Assignments.

(a)    The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 10.6.

(b)    (i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees (each, an “Assignee”) other than a Defaulting Lender, any Subsidiary of a Defaulting Lender, any natural person (or holding

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company, investment vehicle or trust for, or owned or operated by or for the primary benefit of, one or more natural persons), the Borrower or any of the Borrower’s Affiliates or Subsidiaries, all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld or delayed) of:

(A)    the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender (or an Affiliate of any

Lender) or an Approved Fund or, if an Event of Default under Section 8(a), (e) or (f) has occurred and is continuing, any other Person, and provided further, that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within ten (10) Business Days after having received notice thereof from the assigning Lender (with a copy to the Administrative Agent); and

(B)    the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment of any Loans to an Assignee that is a Lender (or an Affiliate of a Lender) immediately prior to giving effect to such assignment.

(ii)    Assignments shall be subject to the following additional conditions:

(A)    except in the case of an assignment to a Lender, an Eligible Assignee that is an Affiliate of any Lender or an assignment of the entire remaining amount of the assigning Lender’s Loans, the amount of the Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $10,000,000 (or, if such Assignee is an Eligible Assignee that is an Affiliate of a Lender, $5,000,000) unless each of the Borrower and the Administrative Agent otherwise consent, provided that (1) no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing and (2) with respect to any Lender party to this Agreement on the Effective Date, such amounts shall be aggregated in respect of such Lender and any Affiliate of such Lender that is an Eligible Assignee;

(B)    the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; and

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(C)    the Assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an administrative questionnaire.

In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the Assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Lender, to each of which the applicable Assignee and assignor hereby irrevocably consent), to (x)

pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent or any Lender hereunder (and interest accrued thereon) and (y) acquire (and fund as appropriate) its full pro rata share of all Loans in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the Assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

(iii)    Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) below, from and after the effective date specified in each Assignment and Assumption the Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, shall have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.14, 2.16, 2.17 and 10.5 but shall be subject to the limitations set forth therein); provided, that except to the extent otherwise expressly agreed by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from the Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 10.6 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

(iv)    The Administrative Agent, acting for this purpose as a non-fiduciary agent of the Borrower (and such agency being solely to establish that the relevant obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations), shall maintain at one of its offices a copy of

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each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, in the absence of manifest error, and the Borrower, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)    Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an Assignee, the Assignee’s completed administrative questionnaire (unless the Assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this

Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

(c)    (i)Any Lender may, without the consent of the Borrower or the Administrative Agent, sell participations to one or more banks or other entities (other than a Defaulting Lender, any holding company, investment vehicle or trust for, or owned or operated by or for the primary benefit of, one or more natural persons, the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver that (1) requires the consent of each Lender directly affected thereby pursuant to the proviso to the second sentence of Section Section 10 and (2) directly affects such Participant. Subject to paragraph (c)(ii) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.14, 2.16 and 2.17 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section.

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(ii)    Notwithstanding anything to the contrary herein, a Participant shall not be entitled to receive any greater payment under Section 2.14 or 2.16 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent to such greater payments. Any Participant that is a Foreign Lender shall not be entitled to the benefits of Section 2.16 unless such Participant complies with Section 2.16(e).

(iii)    Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such loan or other obligation is in registered form under Section

5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(d)    Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central bank having jurisdiction over such Lender, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or Assignee for such Lender as a party hereto.

(e)    The Borrower, upon receipt of written notice from the relevant Lender, agrees to issue Notes to any Lender requiring Notes to facilitate transactions of the type described in paragraph (d) above.

(f)    Notwithstanding the foregoing, any Conduit Lender may assign any or all of the Loans it may have funded hereunder to its designating Lender without the consent of the Borrower or the Administrative Agent and without regard to the limitations set forth in Section 10.6(b). Each of the Borrower, each Lender and the Administrative Agent hereby confirms that it will not institute against a Conduit Lender or join any other Person in instituting against a Conduit Lender any bankruptcy, reorganization, arrangement, insolvency or liquidation proceeding under any state

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bankruptcy or similar law, for one year and one day after the payment in full of the latest maturing commercial paper note issued by such Conduit Lender; provided, however, that each Lender designating any Conduit Lender hereby agrees to indemnify, save and hold harmless each other party hereto for any loss, cost, damage, expense, obligations, penalties, actions, judgments, suits or any kind whatsoever arising out of its inability to institute such a proceeding against such Conduit Lender during such period of forbearance.

10.7    Adjustments; Set off.

(a)    Except to the extent that this Agreement expressly provides for payments to be allocated to a particular Lender, if any Lender (a “Benefitted Lender”) shall receive any payment of all or part of the Obligations owing to it hereunder, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set off, pursuant to events or proceedings of the nature referred to in Section 8(f), or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of the Obligations owing to such other Lender hereunder, such Benefitted Lender shall purchase for cash from the other Lenders a participating interest in such portion of the Obligations owing to each such other Lender hereunder, or shall provide such other Lenders with the benefits of any such collateral, as shall be necessary to cause such Benefitted Lender to share the excess payment or benefits of such collateral ratably with

each of the Lenders; provided, however, that if all or any portion of such excess payment or benefits is thereafter recovered from such Benefitted Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest.

(b)    In addition to any rights and remedies of the Lenders provided by law, including other rights of set-off, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable law, upon any amount becoming due and payable by the Borrower hereunder (whether at the stated maturity, by acceleration or otherwise), after any applicable grace period, to set off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch, Affiliate or agency thereof to or for the credit or the account of the Borrower; provided, that in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.20 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the Obligations owing to such Defaulting Lender as to which it exercised such right of setoff. Each Lender agrees promptly to notify the Borrower and the Administrative Agent after any such

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setoff and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such setoff and application.

10.8    Counterparts; Electronic Execution; Binding Effect. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission, emailed pdf. or any other electronic means that reproduces an image of the actual executed signature page shall be effective as delivery of an original executed counterpart hereof. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Agreement and the transactions contemplated hereby shall be deemed to include an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that nothing herein shall require the Administrative Agent to accept electronic signatures in any form or format without its prior written consent. Without limiting the generality of the foregoing, the Borrower hereby (i) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent and the Lenders, electronic images of this Agreement or any other Loan Documents (in each case, including with respect to any signature pages thereto) shall have the same legal effect, validity and enforceability as any paper original, and (ii) waives any argument, defense or right to contest the validity or enforceability of the Loan Documents based solely on the lack of paper original copies of any Loan Documents, including with respect to any signature pages thereto. This Agreement shall become binding on the parties hereto when it shall have been executed by the Administrative Agent and the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

10.9    Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. Without limiting the foregoing provisions of this Section 10.9, if and to the extent that the enforceability of any provisions in this Agreement relating to Defaulting Lenders shall be limited by Debtor Relief Laws, as determined in good faith by the Administrative Agent,

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as applicable, then such provisions shall be deemed to be in effect only to the extent not so limited.

10.10    Integration. This Agreement and the other Loan Documents represent the entire agreement of the Borrower, the Administrative Agent, and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Administrative Agent, or any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Loan Documents.

10.11    GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

10.12    Submission To Jurisdiction; Waivers. The Borrower hereby irrevocably and unconditionally:

(a)    submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive jurisdiction of the United States District Court for the Southern District of New York sitting in the Borough of Manhattan (or if such court lacks subject matter jurisdiction, the Supreme

Court of the State of New York sitting in the Borough of Manhattan), and any appellate court from any thereof;

(b)    consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)    agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to the Borrower at its address set forth in Section 10.2(a) or at such other address of which the Administrative Agent shall have been notified pursuant thereto;

(d)    agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and

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(e)    waives, to the maximum extent not prohibited by law, and agrees not to assert any right it may have to claim or recover in any legal action or proceeding relating to this Agreement or any other Loan Document any special, exemplary, punitive or consequential damages.

NOTHING IN THIS AGREEMENT OR IN ANY OTHER LOAN DOCUMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRATIVE AGENT OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AGAINST THE BORROWER OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

10.13    Acknowledgments. The Borrower hereby acknowledges that:

(a)    it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents;

(b)    none of the Administrative Agent or any Lender has any fiduciary relationship with or duty to the Borrower arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between Administrative Agent and Lenders, on one hand, and the Borrower, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

(c)    no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower and the Lenders.

10.14    Confidentiality. Each of the Administrative Agent and each Lender agrees to keep confidential in accordance with such party’s customary practices (and in any event in compliance with applicable law regarding material non-public information) all non-public information provided to it by the Borrower, the Administrative Agent or any Lender pursuant to or in connection with this Agreement that is designated by the provider thereof as confidential; provided that nothing herein shall prevent the Administrative Agent or any Lender from disclosing any such information (a) to the Administrative Agent, any other Lender or any Affiliate thereof, (b) subject to an agreement to comply with the provisions of this Section or substantially equivalent provisions, to any actual or prospective Transferee, any direct or indirect counterparty to any Swap Agreement (or any professional advisor to such counterparty) or any credit insurance providers, (c) to its employees, directors, agents, attorneys, service providers, accountants and other professional advisors or those of any of its Affiliates (as long as such attorneys, service providers, accountants and other professional advisors are directed to comply with confidentiality requirements substantially equivalent to this Section), (d) upon the request or demand of any Governmental Authority, (e) in response to any order of any court or other Governmental Authority or as may otherwise be required pursuant to any Requirement of Law, (f) if requested or required to do so in connection with any

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litigation or similar proceeding, (g) that has been publicly disclosed, (h) to the National Association of Insurance Commissioners or any similar organization or any nationally recognized rating agency that requires access to information about a Lender’s investment portfolio in connection with ratings issued with respect to such Lender, (i) in connection with the exercise of any remedy hereunder or under any other Loan Document, (j) any rating agency in connection with rating of the Borrower or its Subsidiaries or the credit facilities provided hereunder or (k) to the extent such information (i) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower or its Subsidiaries or (ii) is independently discovered or developed by a party hereto without utilizing any information received from the Borrower or its Subsidiaries or violating the terms of this Section 10.14, provided that, in the case of clauses (d), (e) and (f) of this Section 10.14, with the exception of disclosure to bank regulatory authorities, the Borrower (to the extent legally permissible) shall be given prompt prior notice so that it may seek a protective order or other appropriate remedy.

10.15    WAIVERS OF JURY TRIAL. TO THE FULLEST EXTENT PERMITTED BY LAW, THE BORROWER, THE ADMINISTRATIVE AGENT AND THE LENDERS HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

10.16    USA Patriot Act; Beneficial Ownership Regulation. Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Patriot Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act.

10.17    Judicial Reference. If any action or proceeding is filed in a court of the State of California by or against any party hereto in connection with any of the

transactions contemplated by this Agreement or any other Loan Document, (i) the court shall, and is hereby directed to, make a general reference pursuant to California Code of Civil Procedure Section 638 to a referee (who shall be a single active or retired judge) to hear and determine all of the issues in such action or proceeding (whether of fact or of law) and to report a statement of decision, provided that at the option of any party to such proceeding, any such issues pertaining to a “provisional remedy” as defined in California Code of Civil Procedure Section 1281.8 shall be heard and determined by the court, and (ii) without limiting the generality of Section 10.5, the Borrower shall be solely responsible to pay all fees and expenses of any referee appointed in such action or proceeding.

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10.18    No Advisory or Fiduciary Responsibility. In connection with all aspects of each transactions contemplated hereby (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document), the Borrower acknowledges and agrees that: (i) (A) the arranging and other services regarding this Agreement provided by the Agents and the Lenders are arm’s-length commercial transactions between the Borrower, on the one hand, and the Agents and the Lenders, on the other hand, (B) the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate, and (C) the Borrower is capable of evaluating, and understands and accepts, the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents; (ii) (A) each Agent and Lender is and has been acting solely as a principal and, except as expressly agreed in writing by the relevant parties, has not been, is not, and will not be acting as an advisor, agent or fiduciary for the Borrower or any other Person and (B) none of the Agents or Lenders has any obligation to the Borrower or any of its Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; and (iii) the Agents and the Lenders and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its Affiliates, and none of the Agents or Lenders has any obligation to disclose any of such interests to the Borrower or its Affiliates. To the fullest extent permitted by law, the Borrower hereby waives and releases any claims that it may have against the Agents and the Lenders with respect to any breach or alleged breach of agency or fiduciary duty in connection with any aspect of any transaction contemplated hereby other than a breach of the confidentiality provisions set forth in Section 10.14.

10.19    Acknowledgement Regarding Any Supported QFCs.

(a)    To the extent that the Loan Documents provide support, through a guarantee or otherwise, for Swap Agreements or any other agreement or instrument that is a QFC (such support “QFC Credit Support” and each such QFC a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Loan Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

(b)    In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and

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such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Loan Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Loan Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support..

10.20    Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)    the effects of any Bail-In Action on any such liability, including, if applicable:

(i)    a reduction in full or in part or cancellation of any such liability;

(ii)    a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)    the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the applicable Resolution Authority.

[Remainder of page intentionally left blank. Signature pages follow.]

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Annex B

Schedule 1.1

Commitments

364-Day Tranche Lender	Commitment
Bank of America, N.A.	$600,000,000.00
Total:	$600,000,000.00

Document

EXHIBIT 10.32

PG&E CORPORATION 2021 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below (sometimes referred to as “you”). The Restricted Stock Units have been granted under the PG&E Corporation 2021 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the “Agreement”).

Date of Grant:     <award_date>

Name of Recipient:      <First_Name> <Last_Name>

Recipient’s Participant ID:      <Emp_Id>

Number of Restricted Stock Units:      <shares_awarded>

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 2025.

Attachment

PG&E CORPORATION 2021 LONG-TERM INCENTIVE PLAN

ANNUAL RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown on the cover sheet, will vest in accordance with the below vesting schedule (the “Normal Vesting Schedule”).<br><br><vesting_schedule><br><br>The amounts payable upon each vesting date are hereby designated separate payments for purposes of Section 409A of the Internal Revenue Code of 1986, as amended (“Code”). Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment will then be cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event that cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the RSUs are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.

EXHIBIT 10.32

Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation will issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date) except as set forth elsewhere in this Agreement.
Voluntary Termination	In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination.
Retirement	In the event of your Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such Retirement had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however, that in the event of your Retirement within 2 years following a Change in Control, those Restricted Stock Units that would have vested within 12 months following such Retirement will be vested and settled as soon as practicable after (but not later than 60 days after) the date of such Retirement. All other unvested Restricted Stock Units will be cancelled. Your voluntary termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.

EXHIBIT 10.32

Death/Disability	In the event of your death or Disability (as defined in Code Section 409A) while you are employed, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder will be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	If your employment is involuntarily terminated other than for cause (1) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation for which you provide services, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Code Section 424(f), or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation for which you provide services, then your Restricted Stock Units will vest and be settled in the same manner as for a “Termination other than for Cause” described above.
Change in Control	In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement.<br><br>If the Restricted Stock Units are neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units will vest immediately preceding and contingent on, the Change in Control and be settled as soon as practicable following the date of the Change in Control.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, your voluntary termination, or your Retirement) within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) will vest on the date of the Change in Control and will be settled as soon as practicable following the date of such separation from service, taking into account any acceleration on account of termination or a change in control.<br><br>In the event of such a separation within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this award) will vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation.

EXHIBIT 10.32

Delay	PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Code Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using a rate not exceeding the maximum applicable withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.”<br><br>Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you will be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence will be twenty-nine (29) months.<br><br>PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You will not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). No Restricted Stock Units and no shares of Stock that have not been issued hereunder may be sold, assigned, transferred, pledged, or otherwise encumbered, other than by will or the laws of decent and distribution, and the Restricted Stock Units may be exercised during the life of the Recipient only by the Recipient or the Recipient’s guardian or legal representative.

EXHIBIT 10.32

No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including provisions of the Officer Severance Policy, and provisions of the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 19, 2019 and available on the PG&E@Work internet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation).
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

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Document

EXHIBIT 10.39

PG&E CORPORATION

2010 EXECUTIVE STOCK OWNERSHIP GUIDELINES

(As adopted effective January 1, 2011, and amended effective December 10, 2025)

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 Committee effective December 11, 2024 to delegate administration of the hardship exception. The Guidelines were further amended by the Committee effective December 10, 2025 to align ownership targets with the leadership structure. 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<br><br>Ownership Target
CEO, PG&E Corporation	6x base salary
EVPs and above, PG&E Corporation and Pacific Gas and Electric Company (Utility), but excluding CEO, PG&E Corporation	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.

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Document

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 Prohibition1

2Scope of the Insider Trading Standard2

3Trading Blackout3

4Transactions Pursuant to SEC Rule 10b5-1 Trading Plans4

5Pre-Clearance Requirements4

6Material Nonpublic Information5

7Additional Restrictions on Certain Types of Transactions6

8Post-Termination Transactions6

9Noncompliance with Insider Trading Laws and the Insider Trading Standard6

Guidelines For Rule 10b5-1 Plans7

Appendix B8

Pre-Clearance Procedures8

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.

1.2    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 or performance share 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.    buying or selling stock;

2.    making an initial contribution election into the PG&E Corporation Stock Fund within the 401(k) plan or the PG&E Corporation Phantom Stock Fund within the SRSP or DC-ESRP;

3.    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 or the PG&E Corporation Phantom Stock Fund,

b.    make an intraplan transfer of an existing account balance into or out of the PG&E Corporation Stock Fund or the PG&E Corporation Phantom Stock Fund,

c.    borrow money against a person’s 401(k) plan account if the loan will result in a liquidation of some or all of that person’s PG&E Corporation Stock Fund balance, or

d.    pre-pay a 401(k) plan loan if the pre-payment will result in investment of loan proceeds in the PG&E Corporation Stock Fund;

4.    selling stock upon exercise of a stock option;

5.    making an initial election to participate in the DRSPP, increasing the level of participation in the DRSPP, or making additional contributions to the DRSPP; and

6.    making an initial election to participate in the ESPP or increasing the amount of payroll deductions in the ESPP.

2.4    Types of transactions not covered by this policy:

1.    vesting of restricted stock units or performance shares or withholding of shares to satisfy a tax withholding obligation on vesting;

2.    exercising stock options absent an accompanying sale of the underlying shares;

3.    automatic purchases of the PG&E Corporation Stock Fund in the 401(k) plan as part of regular payroll deductions;

4.    automatic purchases of PG&E Corporation stock through the ESPP pursuant to an existing election;

5.    automatic purchases of PG&E Corporation Phantom Stock through existing compensation deferral or contribution elections under the SRSP, DC-ESRP, or the Deferred Compensation Plan for Non-Employee Directors;

6.    reinvestment of dividends through the DRSPP pursuant to an existing election; and

7.    reinvestment of dividends pursuant to the DRSPP pursuant to an existing election.

2.5    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.

1.    For employees who are involved in the quarterly earnings process, the blackout periods begin after market close on the 15th day of the last month of each quarter. For employees who are asked to review earnings materials, including draft SEC filings, the blackout periods begin when preliminary earnings results become available.

2.    The quarterly earnings blackout periods end before market open after the first full trading day following the date of release of PG&E’s earnings for that quarter. 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 Monday.

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.

3.4    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

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 and officers at or above the level of Vice President (collectively, the “Pre-Clearance Persons”) are required to pre-clear any proposed transactions in PG&E securities for themselves or their Related Persons. In addition, Pre-Clearance Persons are required to pre-clear 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. Pre-clearance is not required for transactions pursuant to valid Rule 10b5-1 Plans (see Section 4.3 above and Appendix A for approval requirements for Rule 10b5-1 Plans). 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;

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 first 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 on Certain Types of Transactions

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. 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;

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 and the PG&E Corporation Retirement Savings Plan for Union-Represented Employees

“DC-ESRP”: the PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan

“DRSPP”: the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan

“ESPP”: PG&E’s Employee Stock Purchase Program or any successor plan thereto

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;

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.

Former directors and Section 16 officers must continue to pre-clear any proposed transaction in PG&E securities for themselves or their Related Persons with the Pre-Clearance Officer until the expiration of six months from the termination of service.

8

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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

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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 Statement Nos. 333-195902, 333-206457, 333-239544, and 333-256896 on Form S-8 of our reports dated February 11, 2026, 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, 2025.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 11, 2026

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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 11, 2026, 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, 2025.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 11, 2026

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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, 2025 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 11th day of February 2026.

/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/ JOHN O. LARSEN
Kerry W. Cooper	John O. Larsen
/s/ LEO P. DENAULT	/s/ PATRICIA K. POPPE
---	---
Leo P. Denault	Patricia 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

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, 2025 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 11th day of February 2026.

/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/ JOHN O. LARSEN
Edward G. Cannizzaro	John O. Larsen
/s/ KERRY W. COOPER	/s/ PATRICIA K. POPPE
Kerry W. Cooper	Patricia K. Poppe
/s/ LEO P. DENAULT	/s/ WILLIAM L. SMITH
---	---
Leo P. Denault	William L. Smith
/s/ JESSICA L. DENECOUR	/s/ BENJAMIN F. WILSON
Jessica L. Denecour	Benjamin F. Wilson
/s/ MARK E. FERGUSON III	/s/ SUMEET SINGH
Mark E. Ferguson III	Sumeet Singh
/s/ W. CRAIG FUGATE
W. Craig Fugate

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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, 2025 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 11, 2026	/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, 2025 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 11, 2026	/s/ CAROLYN J. BURKE
	Carolyn J. Burke
	Executive Vice President and Chief Financial Officer

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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, 2025 of Pacific Gas and Electric Company;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 11, 2026	/s/ SUMEET SINGH
	Sumeet Singh
	Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery

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, 2025 of Pacific Gas and Electric Company;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 11, 2026	/s/ STEPHANIE N. WILLIAMS
	Stephanie N. Williams
	Vice President, Chief Financial Officer and Controller

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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, 2025 (“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 11, 2026

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, 2025 (“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 11, 2026

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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, 2025 (“Form 10-K”), I, Sumeet Singh, Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery 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
Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery

February 11, 2026

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, 2025 (“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 11, 2026