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|  | UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 |  |
|  |  |  |  |  | FORM | 10-Q |  |  |  |  |  |
(Mark One) |  |  |  |  |  |  |  |  |  |  |  |
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |  |
|  | For the quarterly period ended | June 30, 2025 |  |
|  |  | OR |  |
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |  |
For the transition period from ___________ to __________
Commission File Number |  |  | Exact Name of Registrant as Specified in its Charter |  |  | State or Other Jurisdiction of Incorporation |  | IRS Employer Identification Number
1-12609 |  |  | PG&E Corporation | California |  | 94-3234914
1-2348 |  |  | Pacific Gas and Electric Company | California |  | 94-0742640
PG&E Corporation |  |  |  |  | Pacific Gas and Electric Company |  |
300 Lakeside Drive |  |  |  |  | 300 Lakeside Drive |  |
Oakland, | California | 94612 |  |  |  |  | Oakland, | California | 94612 |  |
Address of principal executive offices, including zip code
PG&E Corporation |  |  |  |  | Pacific Gas and Electric Company |  |
415 | 973-1000 |  |  |  |  |  |  | 415 | 973-7000 |  |
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% redeemable | PCG-PI | NYSE American LLC
6.000% Series A Mandatory Convertible Preferred Stock, no par value | PCG-PrX | The New York Stock Exchange

1

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, 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: | ☒ | Large accelerated filer | ☐ | Accelerated filer
|  | ☐ | Non-accelerated filer |  |  |  |
|  | ☐ | Smaller reporting company | ☐ | Emerging growth company
Pacific Gas and Electric Company: | ☐ | Large accelerated filer | ☐ | Accelerated filer
|  | ☒ | Non-accelerated filer |  |  |  |
|  | ☐ | Smaller reporting 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 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 Sections 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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common stock outstanding as of July 23, 2025: |  |
PG&E Corporation: |  | 2,675,580,992*
Pacific Gas and Electric Company: |  | 264,374,809
*Includes 477,743,590 shares of common stock held by Pacific Gas and Electric Company. |  |

2

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2025
TABLE OF CONTENTS

|  | SEC Form 10-Q Reference Number
UNITS OF MEASUREMENT |
GLOSSARY |
FORWARD-LOOKING STATEMENTS |
RISK FACTORS | Part II, Item 1A
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | Part I, Item 2
| OVERVIEW |
| RESULTS OF OPERATIONS |
| LIQUIDITY AND FINANCIAL RESOURCES |
| LITIGATION MATTERS |
| REGULATORY MATTERS |
| ENVIRONMENTAL MATTERS |
| RISK MANAGEMENT ACTIVITIES |
| CRITICAL ACCOUNTING ESTIMATES |
| ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED |
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS | Part I, Item 1
| PG&E CORPORATION |
| CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
| CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| CONDENSED CONSOLIDATED BALANCE SHEETS |
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| CONDENSED CONSOLIDATED STATEMENTS OF EQUITY |
| PACIFIC GAS AND ELECTRIC COMPANY |
| CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
| CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| CONDENSED CONSOLIDATED BALANCE SHEETS |
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY |
| NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) |
| 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: EQUITY |
| NOTE 7: EARNINGS PER SHARE |
| NOTE 8: DERIVATIVES |
| NOTE 9: FAIR VALUE MEASUREMENTS |
| NOTE 10: WILDFIRE-RELATED CONTINGENCIES |
| NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | Part I, Item 3
CONTROLS AND PROCEDURES | Part I, Item 4
LEGAL PROCEEDINGS | Part II, Item 1
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | Part II, Item 2

3

OTHER INFORMATION | Part II, Item 5
EXHIBITS | Part II, Item 6
SIGNATURES |

4

UNITS OF MEASUREMENT

1 Kilowatt (kW) | = | One thousand watts
1 Kilowatt-Hour (kWh) | = | One kilowatt continuously for one hour
1 Megawatt (MW) | = | One thousand kilowatts
1 Megawatt-Hour (MWh) | = | One megawatt continuously for one hour
1 Gigawatt (GW) | = | One million kilowatts
1 Gigawatt-Hour (GWh) | = | One gigawatt continuously for one hour
1 Kilovolt (kV) | = | One thousand volts
1 MMcf | = | One million cubic feet

5

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

AB | Assembly Bill
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
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
CPUC | California Public Utilities Commission
CRR | congestion revenue rights
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
EMANI | European Mutual Association for Nuclear Insurance
Emergence Date | July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EPS | earnings per common share
Exchange Act | Securities Exchange Act of 1934, as amended
FASB | Financial Accounting Standards Board
FERC | Federal Energy Regulatory Commission
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
Form 10-Q | PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q
FRMMA | Fire Risk Mitigation Memorandum Account
GAAP | United States Generally Accepted Accounting Principles
GHG | greenhouse gas
GRC | general rate case
HSMA | Hazardous Substance Memorandum Account
IOUs | investor-owned utility(ies)
IRC | Internal Revenue Code of 1986, as amended
Lakeside Building | 300 Lakeside Drive, Oakland, California, 94612
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part I, Item 2, of this Form 10-Q
MGP | manufactured gas plants
NAV | net asset value
NEIL | Nuclear Electric Insurance Limited, a mutual insurer owned by utilities with nuclear facilities
OEIS | Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
PD | proposed decision
PERA | Public Employees Retirement Association of New Mexico

6

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
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
RUBA | Residential Uncollectibles Balancing Account
SB | Senate Bill
SEC | United States Securities and Exchange Commission
SFGO | The Utility’s former San Francisco General Office headquarters complex
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)
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
WMCE | Wildfire Mitigation and Catastrophic Events
WMP | Wildfire Mitigation Plan
WMPMA | Wildfire Mitigation Plan Memorandum Account

7

FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of cost savings; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “commit,” “goal,” “target,” “will,” “may,” “should,” “would,” “could,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:
•the extent to which the Wildfire Fund and revised prudency standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires, including whether the Utility maintains an approved WMP and a valid safety certification and whether the Wildfire Fund has sufficient remaining funds (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; the risk that the Utility is not able to recover costs from the Wildfire Fund or other third parties or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations, and proceedings;
•the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; the effectiveness of its system hardening, including undergrounding; the cost of the program and the timing and outcome of any proceeding to recover such costs through rates; and any determination by the OEIS that the Utility has not complied with its WMP;
•the Utility’s ability to safely, reliably, and efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably;
•significant changes to the electric power and natural gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for natural gas; the impact of customer demand falling short of the Utility’s forecasts, driven by customer self-generation, customer departures to community choice aggregators, direct access providers, and government-owned utilities, and legislative mandates to reduce the use of natural gas; and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, increasing demand for electric power due to data centers and electrification of the transportation and other sectors of the economy, and the resulting changes in customer demand for its natural gas and electric services;
•cyber or physical attacks, including cybersecurity breaches, 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 Utility’s ability to attract or retain specialty personnel;
8

•the impact of severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, and other events that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the effectiveness of the Utility’s efforts to prevent, mitigate, or respond to such conditions or events; the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;
•existing and future regulation and federal, state or local legislation, their implementation, and their interpretation; the cost to comply with such regulation and legislation; and the extent to which the Utility recovers its associated compliance and investment costs, including those regarding:
◦wildfires, including inverse condemnation reform, wildfire self-insurance, the Wildfire Fund, and additional wildfire mitigation measures or other reforms targeted at the Utility or its industry;
◦the environment, including the costs incurred to discharge the Utility’s remediation obligations or the costs to comply with standards for GHG emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and electric vehicles;
◦the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, and cooling water intake, and whether DCPP operations are extended; and the Utility’s ability to continue operating DCPP until its planned retirement;
◦the regulation of utilities and their affiliates, including the conditions that apply to PG&E Corporation as the Utility’s holding company;
◦privacy and cybersecurity; and
◦taxes and tax audits;
•the outcome of current and future self-reports, investigations or other enforcement actions, agency compliance reports, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cybersecurity protections; environmental laws and regulations; or otherwise, such as fines; penalties; remediation obligations; or the implementation of corporate governance, operational or other changes in connection with the Enhanced Oversight and Enforcement Process;
•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and the transfer of ownership of the Utility’s assets to municipalities or other public entities, including as a result of the City and County of San Francisco’s valuation petition;
•whether the Utility can control its operating costs within the authorized levels of spending; whether the Utility can continue implementing the Lean operating system and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the risks and uncertainties associated with inflation (including 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;
9

•the risks and uncertainties associated with the resolution of the matters described in Note 10 of the Notes to the Condensed 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;
•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the IRC, as a result of which tax attributes could be limited;
•the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;
•the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;
•the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms, volatility in such capital markets, and changes in interest rates;
•the risks and uncertainties associated with high rates for the Utility’s customers;
•actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings;
•the severity, extent, and duration of pandemics and the Utility’s ability to collect on customer receivables; and
•the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.
For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A: “Risk Factors” in the 2024 Form 10-K and a detailed discussion of these matters contained in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Form 10-K and Part I, Item 2 in this Form 10-Q. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
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PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC located at http://www.sec.gov. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $200,000, a fatality or injury requiring medical attention from a healthcare professional at a hospital or other medical facility, or media coverage from a major news outlet, or a government entity investigating whether the infrastructure owned or operated by the utility caused a wildfire, the Utility is required to submit an electric incident report including information about such incident to the CPUC. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such websites is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the addresses of such websites solely for the information of investors and do not intend the addresses to be active links.
ITEM 1A. RISK FACTORS
For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see Item 1A: “Risk Factors” in the 2024 Form 10-K, as supplemented in the section of this Quarterly Report on Form 10-Q entitled “Forward-Looking Statements.”
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PART I. FINANCIAL INFORMATION
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1. It should also be read in conjunction with the 2024 Form 10-K.
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 Part I, Item 1: “Business” in the 2024 Form 10-K 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, and transportation of natural gas; weather conditions; criminal, civil and regulatory penalties or charges for wildfires; the outcomes of ratemaking proceedings; and changes in interest expense as a result of additional debt issuances or changes in interest rates.
The discussion related to the results of operations and liquidity for the three and six months ended June 30, 2024 compared to the same period in 2023 is incorporated by reference to Part I, Item 2: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the three months ended June 30, 2024, which was filed with the SEC in July 2024.
Key Factors Affecting Financial Results
PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:
•The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, self-insurance, the Wildfire Fund, and regulatory recovery.
In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include Enhanced Powerline Safety Settings (“EPSS”), PSPS, vegetation management, asset inspections, and system hardening (such as undergrounding). The Utility’s wildfire mitigation efforts have also benefited in recent years from improved ignition response and situational awareness tools like weather stations and risk modeling. These initiatives reduce the Utility’s wildfire risk. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.
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 Condensed Consolidated Financial Statements in Part I, Item 1. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.
The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it regularly reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the OEIS based on its ongoing review. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.
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Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate change (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
The financial impact of past wildfires is significant. As of June 30, 2025, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.325 billion, $2.075 billion, and $250 million for claims in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses with the exception of amounts relating to the 2019 Kincade fire, which represent the best estimate of the liability, but 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, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
As of June 30, 2025, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $523 million for the 2021 Dixie fire, and $251 million for the 2022 Mosquito fire. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies.
If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. Such funds are expected to be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund (see Notes 2 and 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1), as a result of claims made by California’s other participating electric utility companies. For example, Edison International and Southern California Edison Company (together, “SCE”) have 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 re-evaluate their estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization when and if SCE accrues a liability or a Wildfire Fund receivable, respectively. The impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, recoveries for the 2019 Kincade fire are 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 $1,075 million for the 2021 Dixie fire, of which it had received $445 million as of June 30, 2025. See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables. As of June 30, 2025, the Utility has recorded receivables for regulatory recovery of $621 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 for more information.
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•The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Regulatory Matters” below.
•PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility 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 depends on capital market conditions. Increased volatility in capital markets and 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 from historical results, see Item 1A: “Risk Factors” in the 2024 Form 10-K and “Forward-Looking Statements” above.
Tax Matters
PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $33.7 billion and a California net operating loss carryforward of approximately $34.9 billion as of December 31, 2024.
Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate value of stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”) contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Accordingly, although PG&E Corporation had 2,675,580,992 common shares outstanding as of July 23, 2025, only 2,197,837,402 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 July 23, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of July 23, 2025 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation.
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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 the three and six months ended June 30, 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 for the three and six months ended June 30, 2025 and 2024:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Consolidated Total | $ | 521 |  |  | $ | 520 |  |  | $ | 1,128 |  |  | $ | 1,252 |
PG&E Corporation | (87) |  |  | (41) |  |  | (172) |  |  | (87) |
Utility | $ | 608 |  |  | $ | 561 |  |  | $ | 1,300 |  |  | $ | 1,339 |

PG&E Corporation’s net loss primarily consists of interest expense on long-term debt.
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Utility
The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 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.

| Three Months Ended June 30, |  | Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Operating Revenues |  |  |  |  |  |  |
Electric | $ | 4,414 |  |  | $ | 4,458 |  |  | $ | 8,549 |  |  | $ | 8,510 |
Natural gas | 1,484 |  |  | 1,528 |  |  | 3,332 |  |  | 3,337 |
Total operating revenues | 5,898 |  |  | 5,986 |  |  | 11,881 |  |  | 11,847 |
Operating Expenses |  |  |  |  |  |  |
Cost of electricity | 599 |  |  | 763 |  |  | 998 |  |  | 1,084 |
Cost of natural gas | 111 |  |  | 204 |  |  | 607 |  |  | 733 |
Operating and maintenance | 2,854 |  |  | 2,753 |  |  | 5,492 |  |  | 5,384 |
Wildfire-related claims, net of recoveries | 50 |  |  | (3) |  |  | 99 |  |  | (4) |
Wildfire Fund expense | 109 |  |  | 78 |  |  | 185 |  |  | 156 |
Depreciation, amortization, and decommissioning | 1,073 |  |  | 1,053 |  |  | 2,170 |  |  | 2,075 |
Total operating expenses | 4,796 |  |  | 4,848 |  |  | 9,551 |  |  | 9,428 |
Operating Income | 1,102 |  |  | 1,138 |  |  | 2,330 |  |  | 2,419 |
Interest income | 179 |  |  | 199 |  |  | 293 |  |  | 333 |
Interest expense | (713) |  |  | (750) |  |  | (1,368) |  |  | (1,404) |
Other income, net | 83 |  |  | 79 |  |  | 154 |  |  | 158 |
Income Before Income Taxes | 651 |  |  | 666 |  |  | 1,409 |  |  | 1,506 |
Income tax provision | 39 |  |  | 101 |  |  | 102 |  |  | 160 |
Net Income | 612 |  |  | 565 |  |  | 1,307 |  |  | 1,346 |
Preferred stock dividend requirement | 4 |  |  | 4 |  |  | 7 |  |  | 7 |
Income Available for Common Stock | $ | 608 |  |  | $ | 561 |  |  | $ | 1,300 |  |  | $ | 1,339 |

Operating Revenues
The Utility’s electric and natural gas operating revenues decreased by $88 million, or 1%, in the three months ended June 30, 2025, compared to the same period in 2024. This decrease was primarily due to:
•approximately $275 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended June 30, 2024, with no comparable revenues in the same period in 2025;
•an a pproximately $50 million reduction in revenues related to self-insurance (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K) in the three months ended June 30, 2025, as compared to the same period in 2024;
•a decrease in revenues to recover the cost of natural gas (which decreased by approximately $90 million) in the three months ended June 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income; and
•a decrease in revenues to recover the cost of electricity procurement (which decreased by approximately $160 million) in the three months ended June 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income.
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Partially offset by:
•approximately $240 million in revenues to recover costs associated with extended operations at DCPP in the three months ended June 30, 2025, with no comparable revenues in the same period in 2024;
•approximately $190 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in the three months ended June 30, 2025, with no comparable revenues in the same period in 2024;
•an approximately $80 million increase in the FERC TO formula rate revenue in the three months ended June 30, 2025, compared to the same period in 2024; and
•approximately $20 million in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in the three months ended June 30, 2025, with no comparable revenues in the same period in 2024.
The Utility’s electric and natural gas operating revenues increased by $34 million, or 0%, in the six months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:
•approximately $370 million in revenues to recover costs associated with extended operations at DCPP in the six months ended June 30, 2025, with no comparable revenues in the same period in 2024;
•approximately $360 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in the six months ended June 30, 2025, with no comparable revenues in the same period in 2024;
•an approximately $150 million increase in the FERC TO formula rate revenue in the six months ended June 30, 2025, compared to the same period in 2024; and
•approximately $50 million in revenues authorized in the GOSMA petition for modification final decision in the six months ended June 30, 2025, with no comparable revenues in the same period in 2024.
Partially offset by:
•approximately $550 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the six months ended June 30, 2024, with no comparable revenues in the same period in 2025;
•an approximately $100 million reduction in revenues related to self-insurance (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K) in the six months ended June 30, 2025, as compared to the same period in 2024;
•approximately $60 million in lower revenues related to winter storm response in the six months ended June 30, 2025, as compared to the same period in 2024;
•a decrease in revenues to recover the cost of natural gas (which decreased by approximately $130 million) in the six months ended June 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income; and
•a decrease in revenues to recover the cost of electricity procurement (which decreased by approximately $90 million) in the six months ended June 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income.
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Cost of Electricity
The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly with third parties.
The Cost of electricity decreased by $164 million, or 21% in the three months ended June 30, 2025, and by $86 million, or 8% in the six months ended June 30, 2025, compared to the same periods in 2024. These decreases were primarily the result of lower procurement costs, partially offset by higher nuclear fuel amortization in the three and six months ended June 30, 2025, compared to the same periods in 2024.
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 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
The Cost of natural gas decreased by $93 million, or 46%, in the three months ended June 30, 2025, and by $126 million, or 17%, in the six months ended June 30, 2025, compared to the same periods in 2024. These decreases were primarily the result of a reduction in GHG emissions expenses and favorable price risk management results, due to less natural gas market price volatility experienced for the present periods, partially offset by increases in natural gas prices and volumes purchased for the present periods, compared to the same periods in 2024.
Operating and Maintenance
The Utility’s Operating and maintenance expenses increased by $101 million, or 4%, in the three months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:
•approximately $220 million in costs associated with extended operations at DCPP in the three months ended June 30, 2025, with no comparable costs in the same period in 2024; and
•approximately $190 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended June 30, 2025, with no comparable costs in the same period in 2024.
Partially offset by:
•the recognition of approximately $275 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended June 30, 2024, with no comparable costs in the same period in 2025; and
•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the three months ended June 30, 2024, with no comparable costs in the same period in 2025. For more information, see “Regulatory Matters” below.
The Utility’s Operating and maintenance expenses increased by $108 million, or 2%, in the six months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:
•approximately $360 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the six months ended June 30, 2025, with no comparable costs in the same period in 2024; and
•approximately $340 million in costs associated with extended operations at DCPP in the six months ended June 30, 2025, with no comparable costs in the same period in 2024.
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Partially offset by:
•approximately $550 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the six months ended June 30, 2024, with no comparable costs in 2025;
•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the six months ended June 30, 2024, with no comparable costs in the same period in 2025. For more information, see “Regulatory Matters” below; and
•approximately $60 million in lower costs related to winter storm response in the six months ended June 30, 2025, as compared to the same period in 2024.
Wildfire-Related Claims, Net of Recoveries
The Utility’s Wildfire-related claims, net of recoveries increased by $53 million, or more than 100%, and $103 million, or more than 100%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. The Utility recognized pre-tax charges of $50 million and $100 million related to the 2019 Kincade fire in the three and six months ended June 30, 2025, respectively, with no comparable costs in the same periods in 2024.
Wildfire Fund Expense
The Utility’s Wildfire Fund expense increased by $31 million, or 40%, and $29 million, or 19%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. These increases were primarily due to accelerated amortization associated with an increase in the Wildfire Fund receivable for the 2021 Dixie fire.
Depreciation, Amortization, and Decommissioning
The Utility's Depreciation, amortization and decommissioning expenses increased by $20 million, or 2%, and $95 million, or 5%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. These increases were primarily due to the growth in plant balance from capital additions.
Interest Income
The Utility’s Interest income decreased by $20 million, or 10%, and $40 million, or 12%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. These decreases were primarily due to a decrease in interest rates and interest-bearing account balances in the six months ended June 30, 2025 compared to the same periods in 2024.
Interest Expense
The Utility’s Interest expense decreased by $37 million, or 5%, and $36 million, or 3%, in the three and six months ended June 30, 2025 compared to the same periods in 2024. These decreases were primarily due to a decrease in short-term debt with higher, variable interest rates, partially offset by an increase in long-term debt.
Other Income, Net
There was no material change to Other income, net for the periods presented.
Income Tax Provision
The Utility’s Income tax provision decreased by $62 million, or 61%, and $58 million, or 36%, in the three and six months ended June 30, 2025, compared to the same periods in 2024, primarily due to higher tax repairs deduction in the three and six months ended June 30, 2025, compared to the same periods in 2024.
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The effective tax rates were 7.9% and 8.1%, and 15.2% and 10.6%, for the three and six months ended June 30, 2025 and 2024, respectively. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2025 and 2024 primarily due to the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Cuts and Jobs Act of 2017.
Import Tariffs
PG&E Corporation and the Utility are assessing the impacts of changes to import tariffs, which could increase the costs they pay for goods and services, and their ability to mitigate such cost increases, including through operational, contractual, or regulatory initiatives.
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. The CPUC granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025. As of June 30, 2025, the waiver expired. As of June 30, 2025, the Utility was in compliance with its authorized regulatory capital structure.
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.
PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
As of June 30, 2025, PG&E Corporation and the Utility had access to approximately $7.5 billion of total liquidity comprised of $236 million of the Utility’s Cash and cash equivalents, $258 million of PG&E Corporation’s Cash and cash equivalents, $1.3 billion of availability under the Utility’s Receivables Securitization Program, and $5.7 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 two 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.
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Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of June 30, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $258 million and $236 million, respectively.
As of June 30, 2025, the Utility had contributed $962 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of June 30, 2025, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, $3 million was classified as Cash and cash equivalents, and $969 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, see “Self-Insurance” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
Financial Resources
Equity Financings
PG&E Corporation has completed the planned equity financing for its $63 billion capital expenditure plan for 2024 through 2028. 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 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
Debt Financings
Utility
The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.
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 expects to use the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount 3.15% First Mortgage Bonds due January 1, 2026.
Credit Facilities and Term Loans
Utility
As of June 30, 2025, PG&E Corporation and the Utility had $650 million and $5.0 billion available under their respective $650 million and $5.4 billion revolving credit facilities. The Utility also has access to the $1.3 billion Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
On April 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity to April 10, 2026. The loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.
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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 up of to $250 million, subject to the satisfaction of certain terms and conditions.
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.
For more information, see “Credit Facilities and Term Loans” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
Other Financings
DOE Loan Guarantee Agreement
On January 17, 2025, the Utility entered into the following agreements: (1) the DOE Loan Guarantee Agreement; (2) a note purchase agreement dated as of January 17, 2025 (the “Note Purchase Agreement”), among the Utility, the Federal Financing Bank (“FFB”), and the DOE; and (3) a future advance promissory note dated January 17, 2025, made by the Utility to FFB (the “Note” and together with the Note Purchase Agreement, the “FFB Note Documents”).
The FFB Note Documents provide for a multi-advance term loan facility (the “Facility”), under which the Utility may make quarterly term loan borrowings through FFB, subject to satisfaction of certain conditions. Proceeds of the advances under the Facility are to be used by the Utility to reimburse for “Eligible Project Costs” previously incurred and either expended or accrued by the Utility in connection with projects that the DOE has determined to be “Eligible Projects” (each as defined in the DOE Loan Guarantee Agreement). The aggregate amount of advances under the Facility may not exceed $15 billion.
As of the date of this report, the Utility has not borrowed any advances under the Facility. The Utility is not able to predict the timing or amount of any funds it may receive from the Facility in the future as a result of the recent change in the administration.
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.
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
Utility
On each of November 29, 2024 and February 20, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 18 and May 15, 2025, to holders of record as of January 31 and April 30, 2025. On May 22, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on August 15, 2025, to holders of record as of July 31, 2025.
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On each of February 20 and May 22, 2025, the Board of Directors of the Utility declared common stock dividends of $575 million, which were paid to PG&E Corporation on March 18 and May 30, 2025, respectively.
PG&E Corporation
On each of November 29, 2024, February 20, and May 22, 2025, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.025 per share, each declaration totaling $55 million, which were paid on January 15, April 15, and July 15, 2025, to holders of record as of December 31, 2024, March 31, and June 30, 2025, respectively.
On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share, totaling $23 million, which was paid on February 27, 2025, to holders of record as of February 14, 2025. On February 20, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, which was paid on May 29, 2025, to holders of record as of May 15, 2025. On May 22, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, payable on September 1, 2025, to holders of record as of August 15, 2025.
Utility Cash Flows
PG&E Corporation’s condensed consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the six months ended June 30, 2025 and 2024.
The Utility’s cash flows were as follows:

| Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |
Net cash provided by operating activities | $ | 4,087 |  |  | $ | 3,114 |  |
Net cash used in investing activities | (6,268) |  |  | (5,225) |  |
Net cash provided by financing activities | 1,661 |  |  | 2,671 |  |
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents | $ | (520) |  |  | $ | 560 |  |

Operating Activities
Net cash provided by operating activities increased by $973 million, or 31%, during the six months ended June 30, 2025 as compared to the same period in 2024. This increase was primarily due to:
•an increase in collections driven in part by recoveries related to DCPP extended operations and 2023 WMCE interim rate relief;
•a decrease in non-wildfire related insurance costs;
•a decrease in payments for employee benefits;
•a decrease in cost of energy as a result of lower carbon allowance purchases; and
•a decrease in wildfire-related payments, net of recoveries.
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base and from cost recovery applications (see “Cost Recovery Proceedings” below for more information).
Future cash flow from operating activities will be affected by various factors, including:
•the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;
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•the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1);
•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 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
Investing Activities
The following table summarizes changes in key components of the Utility’s investing cash flows for the six months ended June 30, 2025, compared to June 30, 2024.

(in millions) | Six Months Ended June 30, |
Cash used in investing activities - 2024 | $ | (5,225) |  |
Capital expenditures | (764) |  |
Net purchases related to customer credit trust investments | (236) |  |
Other investing activities | (43) |  |
Net increase in cash used in investing activities | (1,043) |  |
Cash used in investing activities - 2025 | $ | (6,268) |  |

Net cash used in investing activities increased by $1.0 billion, or 20%, during the six months ended June 30, 2025 as compared to the same period in 2024. This increase was primarily due to a $349 million payment for the purchase of Oakland Headquarters, as discussed in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and an increase in capital work related to electric operations. In addition, there was a $236 million increase in purchases of customer credit trust investments, net of proceeds from sales.
The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur $12.9 billion of capital expenditures in 2025.
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Financing Activities
The following table summarizes changes in key components of the Utility’s financing cash flows for the six months ended June 30, 2025, compared to June 30, 2024.

(in millions) | Six Months Ended June 30,
Cash provided by financing activities - 2024 | $ | 2,671 |
Net borrowings under credit facilities | (511) |
Issuance of long-term debt | 714 |
Repayments of long-term debt | (600) |
Dividend payments | (200) |
Proceeds from DWR loan | (600) |
Other financing activities | 187 |
Net decrease in cash provided by financing activities | (1,010) |
Cash provided by financing activities - 2025 | $ | 1,661 |

Net cash provided by financing activities decreased by $1.0 billion, or 38%, during the six months ended June 30, 2025 as compared to the same period in 2024. The decrease was primarily due to:
•$600 million increase in repayments related to long-term debt;
•$600 million decrease in proceeds related to the DWR loan; and
•$511 million decrease in net borrowings under credit facilities.
Partially offset by:
•$714 million increase in proceeds related to issuance of long-term debt.
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.
LITIGATION MATTERS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and in “Regulatory Matters” below that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
REGULATORY MATTERS
The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the Nuclear Regulatory Commission (“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.
During the quarter ended June 30, 2025 and through the date of this filing, key updates to regulatory matters include the following:
•On July 25, 2025, the CPUC issued a PD that would increase the cost cap for 2025 and 2026 by an aggregate $2.38 billion in connection with the Order Instituting Rulemaking to Establish Energization Timelines.
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•On June 2, 2025, the Utility filed an unopposed all-party settlement with intervenors for an additional $461 million revenue requirement, which is incremental to the previously approved interim rate relief for the 2023 WMCE.
•On May 15, 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 balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, Fire Hazard Prevention Memorandum Account (“FHPMA”), FRMMA, WMPMA,VMBA, Wildfire Mitigation Balancing Account (“WMBA”), and Microgrids Memorandum Account (“MGMA”), among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.
In recent years, the 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 June 30, 2025, the Utility had recorded an aggregate amount of approximately $3.1 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $0.6 billion was authorized for recovery and accounted for as current, and $2.5 billion was accounted for as long term as of June 30, 2025. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
If the amount of the costs recorded in these accounts continues to increase, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
For more information, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below.
The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the six months ended June 30, 2025 are summarized in the following table:

Proceeding |  | Request (1) |  | Status
2022 WMCE |  | Revenue requirement of approximately $1.29 billion |  | Filed December 2022. Decision authorizing $1.1 billion of interim rate relief adopted June 2023. Partial settlement filed December 2023.
2023 WMCE |  | Revenue requirement of approximately $1.86 billion |  | Application filed December 2023. Decision authorizing $944 million of interim rate relief adopted September 2024. Partial settlement filed June 2025.
2024 WMCE |  | Revenue requirement of approximately $435 million |  | Application filed November 2024.
2023 WGSC |  | Revenue requirement of approximately $688 million |  | Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024.

(1) The revenue requirement amounts requested do not include interest.
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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 consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision for such requested rate relief. Cost recovery requested in the 2022 WMCE application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
On December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.
On December 19, 2024, the CPUC extended the statutory deadline to resolve the remaining issues in the proceeding to September 30, 2025.
2023 WMCE Application
On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 WMCE application”). The costs addressed in 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. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in the 2023 WMCE 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.
On April 14, 2025, the CPUC issued a PD that would extend the statutory deadline in this matter to December 1, 2025.
On June 2, 2025, the Utility filed an unopposed all-party settlement with intervenors for an additional $461 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA. The settlement agreement did not address the Utility’s revenue requirement request of $833 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.
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2024 WMCE Application
On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in 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.
Forward-Looking Rate Cases
The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS approves guidelines. See “SB 884 10-Year Distribution Undergrounding Program” below.
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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.
The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the quarter ended June 30, 2025 are summarized in the following table:

Rate Case |  | Request |  | Status
Energization Timelines OIR |  | Capital cost cap increase of $3.13 billion for 2025 and 2026 |  | PD authorizing $2.38 billion increase for 2025 and 2026 cost cap issued in July 2025.
2027 GRC |  | Revenue requirement of $16.64 billion for 2027 |  | Filed May 2025. A decision is requested by the fourth quarter of 2026.
2026 Cost of Capital |  | Increase ROE to 11.30% and cost of debt to 5.05% |  | Filed March 2025.
Transmission Owner Rate Case for 2024 |  | Revenue requirement of $2.78 billion for 2024 |  | Accepted December 2023, except as to CAISO adder. Appeal of FERC’s order regarding CAISO adder denied July 2025. All other issues settled March 2025.

Energization Timelines Order Instituting Rulemaking
As previously disclosed, on July 16, 2024, the CPUC issued a final decision approving a memorandum account with interim rate relief for the Utility to recover energization costs incremental to the forecasts of the Utility’s Phase 1 2023 GRC, subject to annual caps and reasonableness review in the 2027 GRC application. The overall expenditure cap was set at $2.26 billion for the period of 2024 to 2026. The decision also permitted the Utility to request revisions to the 2025 and 2026 cap amounts under certain conditions. On October 4, 2024, the Utility filed a motion to increase the 2025 and 2026 cap amounts by an aggregate $3.13 billion.
On July 25, 2025, the administrative law judge issued a PD that would increase the cost cap for 2025 and 2026 by an aggregate $2.38 billion.
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.
The table below compares the portion of CPUC jurisdictional revenue requirements and weighted-average rate base that are requested in the GRC proceeding 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 | 17.7 |  |  | 73.4 |
2029 | 18.7 |  |  | 79.4 |
2030 | 19.9 |  |  | 85.4 |

29

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 each year 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.
In its application, in accordance with the CPUC’s standard rate case plan schedule, the Utility requests that the CPUC issue a PD by November 1, 2026. It also requests that the 2027 GRC rates be effective January 1, 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. These applications set the cost of capital, ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2026.
In the application, the Utility requests the following cost of capital rates:

|  | Cost |  | Weight |  | Weighted Cost
Return on Common Equity |  | 11.30 | % |  | 52.00% |  | 5.88%
Return on Preferred Equity |  | 5.52 | % |  | 0.30% |  | 0.02%
Return on Long-term debt |  | 5.05 | % |  | 47.70% |  | 2.41%

The application also requests CPUC approval of 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. The scoping memo issued by the CPUC provides for a procedural schedule that would provide a final decision in 2025.
Transmission Owner Rate Cases
Transmission Owner Rate Case for 2024 (the “TO21” rate case)
On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasted a 2024 retail electric transmission revenue requirement of $2.83 billion. The 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 March 21, 2025, the Utility filed with the FERC a settlement in the TO21 rate case. The settlement would resolve 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 settlement would set a base ROE of 10.38%. The settlement would set a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%.
30

Other Regulatory Proceedings
2023-2025 Wildfire Mitigation Plan
The Utility submitted an updated 2025 WMP on April 2, 2024, as directed by the OEIS. On November 19, 2024, the OEIS issued a final approval of the Utility’s 2025 WMP update. On January 16, 2025, the CPUC ratified the OEIS’s approval.
On December 5, 2024, the Utility filed a change order request to update some of the forecasted work in the WMP for 2025. On February 10, 2025, the OEIS issued a decision approving both initiatives in the change order request.
2026-2028 Wildfire Mitigation Plan
On April 4, 2025, the Utility submitted its 2026-2028 WMP to the OEIS. 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.
SB 884 10-Year Distribution Undergrounding Program
On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs.
On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines.
The Utility expects to submit its undergrounding plan to the OEIS in late 2025, before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.
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 “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q, as well as Item 1A: “Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.
RISK MANAGEMENT ACTIVITIES
There have been no material changes to the Utility’s or PG&E Corporation’s risk management activities previously disclosed in the 2024 Form 10-K.
CRITICAL ACCOUNTING ESTIMATES
There have been no material changes to the Utility’s or PG&E Corporation’s critical accounting policies, as previously disclosed in Item 7 of the 2024 Form 10-K.
ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
31

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)

| (Unaudited)
| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Operating Revenues |  |  |  |  |  |  |
Electric | $ | 4,414 |  |  | $ | 4,458 |  |  | $ | 8,549 |  |  | $ | 8,510 |
Natural gas | 1,484 |  |  | 1,528 |  |  | 3,332 |  |  | 3,337 |
Total operating revenues | 5,898 |  |  | 5,986 |  |  | 11,881 |  |  | 11,847 |
Operating Expenses |  |  |  |  |  |  |
Cost of electricity | 599 |  |  | 763 |  |  | 998 |  |  | 1,084 |
Cost of natural gas | 111 |  |  | 204 |  |  | 607 |  |  | 733 |
Operating and maintenance | 2,860 |  |  | 2,757 |  |  | 5,506 |  |  | 5,393 |
Wildfire-related claims, net of recoveries | 50 |  |  | (3) |  |  | 99 |  |  | (4) |
Wildfire Fund expense | 109 |  |  | 78 |  |  | 185 |  |  | 156 |
Depreciation, amortization, and decommissioning | 1,073 |  |  | 1,053 |  |  | 2,170 |  |  | 2,075 |
Total operating expenses | 4,802 |  |  | 4,852 |  |  | 9,565 |  |  | 9,437 |
Operating Income | 1,096 |  |  | 1,134 |  |  | 2,316 |  |  | 2,410 |
Interest income | 181 |  |  | 202 |  |  | 298 |  |  | 339 |
Interest expense | (792) |  |  | (812) |  |  | (1,526) |  |  | (1,527) |
Other income, net | 84 |  |  | 82 |  |  | 154 |  |  | 158 |
Income Before Income Taxes | 569 |  |  | 606 |  |  | 1,242 |  |  | 1,380 |
Income tax provision | 20 |  |  | 82 |  |  | 59 |  |  | 121 |
Net Income | 549 |  |  | 524 |  |  | 1,183 |  |  | 1,259 |
Preferred stock dividend requirement | 28 |  |  | 4 |  |  | 55 |  |  | 7 |
Income Available for Common Shareholders | $ | 521 |  |  | $ | 520 |  |  | $ | 1,128 |  |  | $ | 1,252 |
Weighted Average Common Shares Outstanding, Basic | 2,198 |  |  | 2,137 |  |  | 2,196 |  |  | 2,136 |
Weighted Average Common Shares Outstanding, Diluted | 2,203 |  |  | 2,142 |  |  | 2,201 |  |  | 2,141 |
Net Income Per Common Share, Basic | $ | 0.24 |  |  | $ | 0.24 |  |  | $ | 0.51 |  |  | $ | 0.59 |
Net Income Per Common Share, Diluted | $ | 0.24 |  |  | $ | 0.24 |  |  | $ | 0.51 |  |  | $ | 0.58 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
32

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

| (Unaudited)
| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net Income | $ | 549 |  |  | $ | 524 |  |  | $ | 1,183 |  |  | $ | 1,259 |
Other Comprehensive Income |  |  |  |  |  |  |
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0 respectively) | — |  |  | — |  |  | 1 |  |  | — |
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3, $0, $5 and $1 respectively) | 8 |  |  | — |  |  | 14 |  |  | (1) |
Total other comprehensive income (loss) | 8 |  |  | — |  |  | 15 |  |  | (1) |
Comprehensive Income | 557 |  |  | 524 |  |  | 1,198 |  |  | 1,258 |
Preferred stock dividend requirement | 28 |  |  | 4 |  |  | 55 |  |  | 7 |
Comprehensive Income Available for Common Shareholders | $ | 529 |  |  | $ | 520 |  |  | $ | 1,143 |  |  | $ | 1,251 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
33

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)

| (Unaudited) |  |  |  |
| Balance at |  |  |  |
| June 30, 2025 |  | December 31, 2024 |  |  |  |
ASSETS |  |  |  |  |  |  |
Current Assets |  |  |  |  |  |  |
Cash and cash equivalents | $ | 494 |  |  | $ | 940 |  |  |  |  |
Restricted cash and restricted cash equivalents (includes $207 million and $263 million related to VIEs at respective dates) | 221 |  |  | 273 |  |  |  |  |
Accounts receivable |  |  |  |  |  |  |
Customers (net of allowance for doubtful accounts of $404 million and $418 million at respective dates) (includes $1.7 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $404 million and $418 million at respective dates) | 2,025 |  |  | 2,220 |  |  |  |  |
Accrued unbilled revenue (includes $1.6 billion and $1.3 billion related to VIEs at respective dates) | 1,862 |  |  | 1,487 |  |  |  |  |
Regulatory balancing accounts | 5,657 |  |  | 7,227 |  |  |  |  |
Other (net of allowance for doubtful accounts of $89 million and $35 million at respective dates) | 2,095 |  |  | 1,810 |  |  |  |  |
Regulatory assets | 302 |  |  | 234 |  |  |  |  |
Inventories |  |  |  |  |  |  |
Gas stored underground and fuel oil | 73 |  |  | 52 |  |  |  |  |
Materials and supplies | 713 |  |  | 768 |  |  |  |  |
Wildfire Fund asset | 298 |  |  | 301 |  |  |  |  |
Wildfire self-insurance asset | 969 |  |  | 905 |  |  |  |  |
Other | 452 |  |  | 999 |  |  |  |  |
Total current assets | 15,161 |  |  | 17,216 |  |  |  |  |
Property, Plant, and Equipment |  |  |  |  |  |  |
Property, Plant, and Equipment | 123,445 |  |  | 118,262 |  |  |  |  |
Construction work in progress | 4,636 |  |  | 4,458 |  |  |  |  |
Financing lease ROU asset and other | 7 |  |  | 814 |  |  |  |  |
Total property, plant, and equipment | 128,088 |  |  | 123,534 |  |  |  |  |
Accumulated depreciation | (36,288) |  |  | (35,305) |  |  |  |  |
Net property, plant, and equipment | 91,800 |  |  | 88,229 |  |  |  |  |
Other Noncurrent Assets |  |  |  |  |  |  |
Regulatory assets | 15,853 |  |  | 15,561 |  |  |  |  |
Customer credit trust | 935 |  |  | 377 |  |  |  |  |
Nuclear decommissioning trusts | 4,022 |  |  | 3,833 |  |  |  |  |
Operating lease ROU asset | 500 |  |  | 524 |  |  |  |  |
Wildfire Fund asset | 3,891 |  |  | 4,070 |  |  |  |  |
Other (includes noncurrent accounts receivable of $72 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $18 at respective dates) | 4,222 |  |  | 3,850 |  |  |  |  |
Total other noncurrent assets | 29,423 |  |  | 28,215 |  |  |  |  |
TOTAL ASSETS | $ | 136,384 |  |  | $ | 133,660 |  |  |  |  |

See accompanying Notes to the Condensed Consolidated Financial Statements.
34

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)

| (Unaudited)
| Balance at
| June 30, 2025 |  | December 31, 2024
LIABILITIES AND EQUITY |  |  |
Current Liabilities |  |  |
Short-term borrowings | $ | 1,524 |  |  | $ | 1,523 |
Long-term debt, classified as current (includes $217 million and $222 million related to VIEs at respective dates) | 3,643 |  |  | 2,146 |
Accounts payable |  |  |
Trade creditors | 2,663 |  |  | 2,748 |
Regulatory balancing accounts | 2,516 |  |  | 3,169 |
Other | 862 |  |  | 748 |
Operating lease liabilities | 88 |  |  | 85 |
Financing lease liabilities | 1 |  |  | 577 |
Interest payable (includes $65 million and $91 million related to VIEs at respective dates) | 767 |  |  | 760 |
Wildfire-related claims | 787 |  |  | 916 |
Other | 3,334 |  |  | 3,658 |
Total current liabilities | 16,185 |  |  | 16,330 |
Noncurrent Liabilities |  |  |
Long-term debt (includes $10.2 billion and $10.1 billion related to VIEs at respective dates) | 54,004 |  |  | 53,569 |
Regulatory liabilities | 19,871 |  |  | 19,417 |
Pension and other postretirement benefits | 824 |  |  | 808 |
Asset retirement obligations | 5,499 |  |  | 5,444 |
Deferred income taxes | 3,550 |  |  | 3,082 |
Operating lease liabilities | 412 |  |  | 439 |
Financing lease liabilities | 3 |  |  | 4 |
Other | 4,598 |  |  | 4,166 |
Total noncurrent liabilities | 88,761 |  |  | 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; 2,197,837,402 and 2,193,573,536 shares outstanding at respective dates | 31,560 |  |  | 31,555 |
Reinvested earnings | (1,949) |  |  | (2,966) |
Accumulated other comprehensive loss | (4) |  |  | (19) |
Total shareholders’ equity | 31,186 |  |  | 30,149 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 |  |  | 252 |
Total equity | 31,438 |  |  | 30,401 |
TOTAL LIABILITIES AND EQUITY | $ | 136,384 |  |  | $ | 133,660 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
35

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

| (Unaudited)
| Six Months Ended June 30,
| 2025 |  | 2024
Cash Flows from Operating Activities |  |  |
Net income | $ | 1,183 |  |  | $ | 1,259 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation, amortization, and decommissioning | 2,170 |  |  | 2,075 |
Bad debt expense | 241 |  |  | 135 |
Allowance for equity funds used during construction | (97) |  |  | (84) |
Deferred income taxes and tax credits, net | 472 |  |  | 485 |
Wildfire Fund expense | 185 |  |  | 156 |
Other | (29) |  |  | (134) |
Effect of changes in operating assets and liabilities: |  |  |
Accounts receivable | (562) |  |  | (960) |
Wildfire-related insurance receivable | (133) |  |  | 196 |
Inventories | 34 |  |  | 47 |
Accounts payable | 188 |  |  | 419 |
Wildfire-related claims | (129) |  |  | (483) |
Other current assets and liabilities | (76) |  |  | (692) |
Regulatory assets, liabilities, and balancing accounts, net | 750 |  |  | 734 |
Other noncurrent assets and liabilities | (292) |  |  | (181) |
Net cash provided by operating activities | 3,905 |  |  | 2,972 |
Cash Flows from Investing Activities |  |  |
Capital expenditures | (5,700) |  |  | (4,936) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 779 |  |  | 1,044 |
Purchases of nuclear decommissioning trust investments | (809) |  |  | (1,082) |
Proceeds from sales and maturities of customer credit trust investments | 196 |  |  | 174 |
Purchases of customer credit investments | (693) |  |  | (435) |
Proceeds from self-insurance investments | 186 |  |  | — |
Purchases of self-insurance investments | (237) |  |  | — |
Other | 10 |  |  | 10 |
Net cash used in investing activities | (6,268) |  |  | (5,225) |
Cash Flows from Financing Activities |  |  |
Borrowings under credit facilities | 515 |  |  | 5,528 |
Repayments under credit facilities | (325) |  |  | (4,827) |
Repayments under term loan | — |  |  | (100) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $27 and $9 at respective dates | 2,973 |  |  | 2,259 |
Repayments of long-term debt | (1,050) |  |  | (450) |
Repayment of AB 1054 recovery bonds | (48) |  |  | (23) |
Repayment of SB 901 recovery bonds | (67) |  |  | (64) |
Common stock dividends paid | (110) |  |  | (43) |
Mandatory convertible preferred stock dividends paid | (48) |  |  | — |
Proceeds from DWR loan | — |  |  | 600 |
Other | 25 |  |  | (7) |

36

Net cash provided by financing activities | 1,865 |  |  | 2,873 |
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents | (498) |  |  | 620 |
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 | 1,213 |  |  | 932 |
Cash, cash equivalents, restricted cash, and restricted cash equivalents at June 30 | $ | 715 |  |  | $ | 1,552 |
Less: Restricted cash and restricted cash equivalents | (221) |  |  | (237) |
Cash and cash equivalents at June 30 | $ | 494 |  |  | $ | 1,315 |

Supplemental disclosures of cash flow information |  |  |
Cash paid for: |  |  |
Interest, net of amounts capitalized | $ | (1,282) |  |  | $ | (1,199) |
Supplemental disclosures of noncash investing and financing activities |  |  |
Capital expenditures financed through accounts payable | $ | 1,009 |  |  | $ | 921 |
Operating lease liabilities arising from ROU assets | — |  |  | 1 |
Financing lease liabilities arising from obtaining ROU assets | — |  |  | 15 |
DWR loan forgiveness and performance-based disbursements | 78 |  |  | 47 |
Common stock dividends declared but not yet paid | 55 |  |  | 21 |
Mandatory convertible preferred stock dividends declared but not yet paid | 24 |  |  | — |
Capital expenditures financed through current assets and non-current liabilities | 592 |  |  | — |

See accompanying Notes to the Condensed Consolidated Financial Statements.
37

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except share amounts)

| Preferred Stock |  | Common Stock |  | Treasury Stock |  | Reinvested Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Total Shareholders' Equity |  | Non- controlling Interest - Preferred Stock of Subsidiary |  | Total Equity
|  | Shares |  | Amount |  | Shares |  | Amount |  |  |  |  |
Balance at December 31, 2024 | $ | 1,579 |  |  | 2,193,573,536 |  |  | $ | 31,555 |  |  | — |  |  | $ | — |  |  | $ | (2,966) |  |  | $ | (19) |  |  | $ | 30,149 |  |  | $ | 252 |  |  | $ | 30,401 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 634 |  |  | — |  |  | 634 |  |  | — |  |  | 634 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 7 |  |  | — |  |  | 7 |
Common stock issued, net | — |  |  | 4,111,477 |  |  | (1) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1) |  |  | — |  |  | (1) |
Stock-based compensation amortization | — |  |  | — |  |  | (22) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (22) |  |  | — |  |  | (22) |
Common stock dividends declared | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (55) |  |  | — |  |  | (55) |  |  | — |  |  | (55) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (27) |  |  | — |  |  | (27) |  |  | — |  |  | (27) |
Balance at March 31, 2025 | $ | 1,579 |  |  | 2,197,685,013 |  |  | $ | 31,532 |  |  | — |  |  | $ | — |  |  | $ | (2,414) |  |  | $ | (12) |  |  | $ | 30,685 |  |  | $ | 252 |  |  | $ | 30,937 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 549 |  |  | — |  |  | 549 |  |  | — |  |  | 549 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |  |  | — |  |  | 8 |
Common stock issued, net | — |  |  | 152,389 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation amortization | — |  |  | — |  |  | 28 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 28 |  |  | — |  |  | 28 |
Common stock dividends declared | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (56) |  |  | — |  |  | (56) |  |  | — |  |  | (56) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (28) |  |  | — |  |  | (28) |  |  | — |  |  | (28) |
Balance at June 30, 2025 | $ | 1,579 |  |  | 2,197,837,402 |  |  | $ | 31,560 |  |  | — |  |  | $ | — |  |  | $ | (1,949) |  |  | $ | (4) |  |  | $ | 31,186 |  |  | $ | 252 |  |  | $ | 31,438 |

38

| Common Stock |  | Treasury Stock |  | Reinvested Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Total Shareholders' Equity |  | Non- controlling Interest - Preferred Stock of Subsidiary |  | Total Equity
| Shares |  | Amount |  | Shares |  | Amount |  |  |  |  |
Balance at December 31, 2023 | 2,133,597,758 |  |  | $ | 30,374 |  |  | — |  |  | $ | — |  |  | $ | (5,321) |  |  | $ | (13) |  |  | $ | 25,040 |  |  | $ | 252 |  |  | $ | 25,292 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | 735 |  |  | — |  |  | 735 |  |  | — |  |  | 735 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1) |  |  | (1) |  |  | — |  |  | (1) |
Common stock issued, net | 3,558,470 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation amortization | — |  |  | (18) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (18) |  |  | — |  |  | (18) |
Common stock dividends declared | — |  |  | — |  |  | — |  |  | — |  |  | (22) |  |  | — |  |  | (22) |  |  | — |  |  | (22) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | — |  |  | (3) |  |  | — |  |  | (3) |  |  | — |  |  | (3) |
Balance at March 31, 2024 | 2,137,156,228 |  |  | $ | 30,356 |  |  | — |  |  | $ | — |  |  | $ | (4,611) |  |  | $ | (14) |  |  | $ | 25,731 |  |  | $ | 252 |  |  | $ | 25,983 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | 524 |  |  | — |  |  | 524 |  |  | — |  |  | 524 |
Common stock issued, net | 304,127 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Stock-based compensation amortization | — |  |  | 23 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 23 |  |  | — |  |  | 23 |
Common stock dividends declared | — |  |  | — |  |  | — |  |  | — |  |  | (21) |  |  | — |  |  | (21) |  |  | — |  |  | (21) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | — |  |  | (4) |  |  | — |  |  | (4) |  |  | — |  |  | (4) |
Balance at June 30, 2024 | 2,137,460,355 |  |  | $ | 30,379 |  |  | — |  |  | $ | — |  |  | $ | (4,112) |  |  | $ | (14) |  |  | $ | 26,253 |  |  | $ | 252 |  |  | $ | 26,505 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
39

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions)

| (Unaudited)
| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Operating Revenues |  |  |  |  |  |  |
Electric | $ | 4,414 |  |  | $ | 4,458 |  |  | $ | 8,549 |  |  | $ | 8,510 |
Natural gas | 1,484 |  |  | 1,528 |  |  | 3,332 |  |  | 3,337 |
Total operating revenues | 5,898 |  |  | 5,986 |  |  | 11,881 |  |  | 11,847 |
Operating Expenses |  |  |  |  |  |  |
Cost of electricity | 599 |  |  | 763 |  |  | 998 |  |  | 1,084 |
Cost of natural gas | 111 |  |  | 204 |  |  | 607 |  |  | 733 |
Operating and maintenance | 2,854 |  |  | 2,753 |  |  | 5,492 |  |  | 5,384 |
Wildfire-related claims, net of recoveries | 50 |  |  | (3) |  |  | 99 |  |  | (4) |
Wildfire Fund expense | 109 |  |  | 78 |  |  | 185 |  |  | 156 |
Depreciation, amortization, and decommissioning | 1,073 |  |  | 1,053 |  |  | 2,170 |  |  | 2,075 |
Total operating expenses | 4,796 |  |  | 4,848 |  |  | 9,551 |  |  | 9,428 |
Operating Income | 1,102 |  |  | 1,138 |  |  | 2,330 |  |  | 2,419 |
Interest income | 179 |  |  | 199 |  |  | 293 |  |  | 333 |
Interest expense | (713) |  |  | (750) |  |  | (1,368) |  |  | (1,404) |
Other income, net | 83 |  |  | 79 |  |  | 154 |  |  | 158 |
Income Before Income Taxes | 651 |  |  | 666 |  |  | 1,409 |  |  | 1,506 |
Income tax provision | 39 |  |  | 101 |  |  | 102 |  |  | 160 |
Net Income | 612 |  |  | 565 |  |  | 1,307 |  |  | 1,346 |
Preferred stock dividend requirement | 4 |  |  | 4 |  |  | 7 |  |  | 7 |
Income Available for Common Stock | $ | 608 |  |  | $ | 561 |  |  | $ | 1,300 |  |  | $ | 1,339 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
40

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

| (Unaudited)
| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net Income | $ | 612 |  |  | $ | 565 |  |  | $ | 1,307 |  |  | $ | 1,346 |
Other Comprehensive Income |  |  |  |  |  |  |
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0 respectively) | — |  |  | — |  |  | 1 |  |  | — |
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3, $0, $5 and $1 respectively) | 8 |  |  | — |  |  | 14 |  |  | (1) |
Total other comprehensive income (loss) | 8 |  |  | — |  |  | 15 |  |  | (1) |
Comprehensive Income | $ | 620 |  |  | $ | 565 |  |  | $ | 1,322 |  |  | $ | 1,345 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
41

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)

| (Unaudited)
| Balance at
| June 30, 2025 |  | December 31, 2024
ASSETS |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 236 |  |  | $ | 705 |
Restricted cash and restricted cash equivalents (includes $207 million and $263 million related to VIEs at respective dates) | 221 |  |  | 272 |
Accounts receivable |  |  |
Customers (net of allowance for doubtful accounts of $404 million and $418 million at respective dates) (includes $1.7 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $404 million and $418 million at respective dates) | 2,025 |  |  | 2,220 |
Accrued unbilled revenue (includes $1.6 billion and $1.3 billion related to VIEs at respective dates) | 1,862 |  |  | 1,487 |
Regulatory balancing accounts | 5,657 |  |  | 7,227 |
Other (net of allowance for doubtful accounts of $89 million and $35 million at respective dates) | 2,097 |  |  | 1,810 |
Regulatory assets | 302 |  |  | 234 |
Inventories |  |  |
Gas stored underground and fuel oil | 73 |  |  | 52 |
Materials and supplies | 713 |  |  | 768 |
Wildfire Fund asset | 298 |  |  | 301 |
Wildfire self-insurance asset | 969 |  |  | 905 |
Other | 449 |  |  | 998 |
Total current assets | 14,902 |  |  | 16,979 |
Property, Plant, and Equipment |  |  |
Property, Plant, and Equipment | 123,445 |  |  | 118,262 |
Construction work in progress | 4,635 |  |  | 4,458 |
Financing lease ROU asset and other | 7 |  |  | 814 |
Total property, plant, and equipment | 128,087 |  |  | 123,534 |
Accumulated depreciation | (36,287) |  |  | (35,304) |
Net property, plant, and equipment | 91,800 |  |  | 88,230 |
Other Noncurrent Assets |  |  |
Regulatory assets | 15,853 |  |  | 15,561 |
Customer credit trust | 935 |  |  | 377 |
Nuclear decommissioning trusts | 4,022 |  |  | 3,833 |
Operating lease ROU asset | 496 |  |  | 519 |
Wildfire Fund asset | 3,891 |  |  | 4,070 |
Other (includes noncurrent accounts receivable of $72 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $18 at respective dates) | 4,062 |  |  | 3,697 |
Total other noncurrent assets | 29,259 |  |  | 28,057 |
TOTAL ASSETS | $ | 135,961 |  |  | $ | 133,266 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
42

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)

| (Unaudited)
| Balance at
| June 30, 2025 |  | December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY |  |  |
Current Liabilities |  |  |
Short-term borrowings | $ | 1,524 |  |  | $ | 1,523 |
Long-term debt, classified as current (includes $217 million and $222 million related to VIEs at respective dates) | 3,643 |  |  | 2,146 |
Accounts payable |  |  |
Trade creditors | 2,661 |  |  | 2,745 |
Regulatory balancing accounts | 2,516 |  |  | 3,169 |
Other | 842 |  |  | 729 |
Operating lease liabilities | 88 |  |  | 85 |
Financing lease liabilities | 1 |  |  | 577 |
Interest payable (includes $65 million and $91 million related to VIEs at respective dates) | 675 |  |  | 667 |
Wildfire-related claims | 787 |  |  | 916 |
Other | 3,056 |  |  | 3,331 |
Total current liabilities | 15,793 |  |  | 15,888 |
Noncurrent Liabilities |  |  |
Long-term debt (includes $10.2 billion and $10.1 billion related to VIEs at respective dates) | 48,387 |  |  | 47,958 |
Regulatory liabilities | 19,871 |  |  | 19,417 |
Pension and other postretirement benefits | 757 |  |  | 741 |
Asset retirement obligations | 5,499 |  |  | 5,444 |
Deferred income taxes | 4,127 |  |  | 3,632 |
Operating lease liabilities | 408 |  |  | 434 |
Financing lease liabilities | 3 |  |  | 4 |
Other | 4,626 |  |  | 4,198 |
Total noncurrent liabilities | 83,678 |  |  | 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 | 36,705 |  |  | 35,930 |
Reinvested earnings | (1,790) |  |  | (1,940) |
Accumulated other comprehensive loss | (5) |  |  | (20) |
Total shareholders’ equity | 36,490 |  |  | 35,550 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 135,961 |  |  | $ | 133,266 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
43

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

| (Unaudited)
| Six Months Ended June 30,
| 2025 |  | 2024
Cash Flows from Operating Activities |  |  |
Net income | $ | 1,307 |  |  | $ | 1,346 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation, amortization, and decommissioning | 2,170 |  |  | 2,075 |
Bad debt expense | 241 |  |  | 135 |
Allowance for equity funds used during construction | (97) |  |  | (84) |
Deferred income taxes and tax credits, net | 498 |  |  | 529 |
Wildfire Fund expense | 185 |  |  | 156 |
Other | (40) |  |  | (154) |
Effect of changes in operating assets and liabilities: |  |  |
Accounts receivable | (564) |  |  | (960) |
Wildfire-related insurance receivable | (133) |  |  | 196 |
Inventories | 34 |  |  | 47 |
Accounts payable | 188 |  |  | 408 |
Wildfire-related claims | (129) |  |  | (483) |
Other current assets and liabilities | (35) |  |  | (652) |
Regulatory assets, liabilities, and balancing accounts, net | 749 |  |  | 734 |
Other noncurrent assets and liabilities | (287) |  |  | (179) |
Net cash provided by operating activities | 4,087 |  |  | 3,114 |
Cash Flows from Investing Activities |  |  |
Capital expenditures | (5,700) |  |  | (4,936) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 779 |  |  | 1,044 |
Purchases of nuclear decommissioning trust investments | (809) |  |  | (1,082) |
Proceeds from sales and maturities of customer credit trust investments | 196 |  |  | 174 |
Purchases of customer credit investments | (693) |  |  | (435) |
Proceeds from self-insurance investments | 186 |  |  | — |
Purchases of self-insurance investments | (237) |  |  | — |
Other | 10 |  |  | 10 |
Net cash used in investing activities | (6,268) |  |  | (5,225) |
Cash Flows from Financing Activities |  |  |
Borrowings under credit facilities | 515 |  |  | 5,528 |
Repayments under credit facilities | (325) |  |  | (4,827) |
Repayments under term loan | — |  |  | (100) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $27 and $9 at respective dates | 2,973 |  |  | 2,259 |
Repayments of long-term debt | (1,050) |  |  | (450) |
Repayment of AB 1054 recovery bonds | (48) |  |  | (23) |
Repayment of SB 901 recovery bonds | (67) |  |  | (64) |
Preferred stock dividends paid | (7) |  |  | (7) |
Common stock dividends paid | (1,150) |  |  | (950) |
Equity contribution from PG&E Corporation | 775 |  |  | 705 |

44

Proceeds from DWR loan | — |  |  | 600 |
Other | 45 |  |  | — |
Net cash provided by financing activities | 1,661 |  |  | 2,671 |
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents | (520) |  |  | 560 |
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 | 977 |  |  | 736 |
Cash, cash equivalents, restricted cash, and restricted cash equivalents at June 30 | $ | 457 |  |  | $ | 1,296 |
Less: Restricted cash and restricted cash equivalents | (221) |  |  | (236) |
Cash and cash equivalents at June 30 | $ | 236 |  |  | $ | 1,060 |

Supplemental disclosures of cash flow information |  |  |
Cash paid for: |  |  |
Interest, net of amounts capitalized | $ | (1,129) |  |  | $ | (1,083) |
Supplemental disclosures of noncash investing and financing activities |  |  |
Capital expenditures financed through accounts payable | $ | 1,009 |  |  | $ | 921 |
Operating lease liabilities arising from obtaining ROU assets | — |  |  | 1 |
Financing lease liabilities arising from obtaining ROU assets | — |  |  | 15 |
DWR loan forgiveness and performance-based disbursements | 78 |  |  | 47 |
Capital expenditures financed through current assets and non-current liabilities | 592 |  |  | — |

See accompanying Notes to the Condensed Consolidated Financial Statements.
45

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions)

| Preferred Stock |  | Common Stock |  | Additional Paid-in Capital |  | Reinvested Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Total Shareholders' Equity
Balance at December 31, 2024 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 35,930 |  |  | $ | (1,940) |  |  | $ | (20) |  |  | $ | 35,550 |
Net income | — |  |  | — |  |  | — |  |  | 695 |  |  | — |  |  | 695 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 7 |
Equity contribution | — |  |  | — |  |  | 450 |  |  | — |  |  | — |  |  | 450 |
Common stock dividend | — |  |  | — |  |  | — |  |  | (575) |  |  | — |  |  | (575) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | (3) |  |  | — |  |  | (3) |
Balance at March 31, 2025 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 36,380 |  |  | $ | (1,823) |  |  | $ | (13) |  |  | $ | 36,124 |
Net income | — |  |  | — |  |  | — |  |  | 612 |  |  | — |  |  | 612 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |
Equity contribution | — |  |  | — |  |  | 325 |  |  | — |  |  | — |  |  | 325 |
Common stock dividend | — |  |  | — |  |  | — |  |  | (575) |  |  | — |  |  | (575) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | (4) |  |  | — |  |  | (4) |
Balance at June 30, 2025 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 36,705 |  |  | $ | (1,790) |  |  | $ | (5) |  |  | $ | 36,490 |

| Preferred Stock |  | Common Stock |  | Additional Paid-in Capital |  | Reinvested Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Total Shareholders' Equity
Balance at December 31, 2023 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 30,570 |  |  | $ | (2,613) |  |  | $ | (13) |  |  | $ | 29,524 |
Net income | — |  |  | — |  |  | — |  |  | 781 |  |  | — |  |  | 781 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (1) |  |  | (1) |
Equity contribution | — |  |  | — |  |  | 440 |  |  | — |  |  | — |  |  | 440 |
Common stock dividend | — |  |  | — |  |  | — |  |  | (450) |  |  | — |  |  | (450) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | (3) |  |  | — |  |  | (3) |
Balance at March 31, 2024 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 31,010 |  |  | $ | (2,285) |  |  | $ | (14) |  |  | $ | 30,291 |
Net income | — |  |  | — |  |  | — |  |  | 565 |  |  | — |  |  | 565 |
Equity contribution | — |  |  | — |  |  | 265 |  |  | — |  |  | — |  |  | 265 |
Common stock dividend | — |  |  | — |  |  | — |  |  | (500) |  |  | — |  |  | (500) |
Preferred stock dividend requirement | — |  |  | — |  |  | — |  |  | (4) |  |  | — |  |  | (4) |
Balance at June 30, 2024 | $ | 258 |  |  | $ | 1,322 |  |  | $ | 31,275 |  |  | $ | (2,224) |  |  | $ | (14) |  |  | $ | 30,617 |

See accompanying Notes to the Condensed Consolidated Financial Statements.
46

NOTES TO THE CONDENSED 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 Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed 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 Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.
The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information as of December 31, 2024 in the Condensed Consolidated Balance Sheets included in this Quarterly Report on Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2024 Form 10-K. This Quarterly Report on Form 10-Q should be read in conjunction with the 2024 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, asset retirement obligations, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed 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
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 (“CODM”) is the Chief Executive Officer of PG&E Corporation.
Net income (loss) is the measure that the CODM 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 Condensed 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 Condensed Consolidated Financial Statements.
PG&E Corporation and the Utility do not have any significant segment expenses because the CODM is not regularly provided with information that is considered to be significant under Accounting Standards Codification (“ASC”) 280, Segment Reporting. Except for publicly available information, the information regularly provided to the CODM 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.
47

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 Condensed 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.
48

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Electric |  |  |  |  |  |  |
Revenue from contracts with customers |  |  |  |  |  |  |
Residential | $ | 1,421 |  |  | $ | 1,516 |  |  | $ | 3,255 |  |  | $ | 3,315 |
Commercial | 1,613 |  |  | 1,655 |  |  | 3,119 |  |  | 3,160 |
Industrial | 386 |  |  | 441 |  |  | 800 |  |  | 854 |
Agricultural | 478 |  |  | 439 |  |  | 677 |  |  | 619 |
Public street and highway lighting | 26 |  |  | 27 |  |  | 53 |  |  | 52 |
Other, net (1) | 665 |  |  | 798 |  |  | 754 |  |  | 919 |
Total revenue from contracts with customers - electric | 4,589 |  |  | 4,876 |  |  | 8,658 |  |  | 8,919 |
Regulatory balancing accounts (2) | (175) |  |  | (418) |  |  | (109) |  |  | (409) |
Total electric operating revenue | $ | 4,414 |  |  | $ | 4,458 |  |  | $ | 8,549 |  |  | $ | 8,510 |
Natural gas |  |  |  |  |  |  |
Revenue from contracts with customers |  |  |  |  |  |  |
Residential | $ | 430 |  |  | $ | 213 |  |  | $ | 2,139 |  |  | $ | 1,730 |
Commercial | 222 |  |  | 187 |  |  | 621 |  |  | 560 |
Transportation service only | 456 |  |  | 424 |  |  | 1,002 |  |  | 899 |
Other, net (1) | (147) |  |  | (138) |  |  | (267) |  |  | (202) |
Total revenue from contracts with customers - gas | 961 |  |  | 686 |  |  | 3,495 |  |  | 2,987 |
Regulatory balancing accounts (2) | 523 |  |  | 842 |  |  | (163) |  |  | 350 |
Total natural gas operating revenue | 1,484 |  |  | 1,528 |  |  | 3,332 |  |  | 3,337 |
Total operating revenues | $ | 5,898 |  |  | $ | 5,986 |  |  | $ | 11,881 |  |  | $ | 11,847 |

(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 June 30, 2025, PG&E Corporation and the Utility identified the following significant categories of financial assets.
Trade Receivables
Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.
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Expected credit losses of $141 million and $241 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables during the three and six months ended June 30, 2025, respectively. For the three and six months ended June 30, 2024, expected credit losses were $65 million and $135 million, 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 June 30, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $146 million and $90 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. The RUBA current balancing account balance decreased from December 31, 2024 to June 30, 2025 primarily due to the annual electric and gas true-up, which allows the Utility to recover approximately $260 million in undercollections from residential customers in 2025.
Other Receivables and Available-For-Sale Debt Securities
Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.
As of June 30, 2025, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Government Assistance
The Utility participated in various government assistance programs during the three months ended June 30, 2025 and 2024. The Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.
DWR Loan Agreement
On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. For more information about the DWR Loan Agreement, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.
The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.
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The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Long-term debt: |  |  |  |  |  |  |
Beginning Balance - DWR loan outstanding | $ | 812 |  |  | $ | 296 |  |  | $ | 886 |  |  | $ | 98 |
Proceeds received | — |  |  | 368 |  |  | — |  |  | 600 |
Operating Expenses: |  |  |  |  |  |  |
Operating and maintenance expense - Performance-based disbursements | (10) |  |  | (17) |  |  | (18) |  |  | (39) |
Operating and maintenance expense - Loan forgiveness and other adjustments | — |  |  | 12 |  |  | (57) |  |  | 12 |
Other current liabilities: |  |  |  |  |  |  |
Change in performance-based disbursements deferred | 6 |  |  | (8) |  |  | (3) |  |  | (20) |
Long-term debt: |  |  |  |  |  |  |
Ending Balance - DWR loan outstanding | $ | 808 |  |  | $ | 651 |  |  | $ | 808 |  |  | $ | 651 |

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 three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $60 million and $100 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 three and six months ended June 30, 2024, the Condensed Consolidated Statements of Income reflected $159 million and $299 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 three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $16 million and $57 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.
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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 Condensed 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 six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2025 and December 31, 2024, the SPV had net accounts receivable of $3.3 billion and $3.2 billion, respectively, and outstanding borrowings of $190 million 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 six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of June 30, 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 Condensed 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 six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of June 30, 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 Condensed Consolidated Balance Sheets. For more information, see Note 5 below.
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Non-Consolidated VIEs
Power Purchase Agreement s
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 June 30, 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 June 30, 2025, it did not consolidate any of them.
Contributions to the Wildfire Fund Established Pursuant to AB 1054
AB 1054 did not specify a period of coverage for the Wildfire Fund, and so the accounting treatment is subject to significant judgments and estim ates. 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 esti mating 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 the first quarter of 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 another participating electric utility discloses a Wildfire Fund receivable.
As of June 30, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $567 million in Other noncurrent liabilities, $298 million in Current assets - Wildfire Fund asset, and $3.9 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2025 and 2024, the Utility recorded amortization and accretion expense of $109 million and $78 million, respectively. During the six months ended June 30, 2025 and 2024, the Utility recorded amortization and accretion expense of $185 million and $156 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 Condensed Consolidated Statements of Income.
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For more information, see “Wildfire Fund under AB 1054” in Note 10 below.
Oakland Headquarters Purchase
On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Lakeside Building (the "Property"). 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 Condensed Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities.
Pension and Other Post-Retirement Benefits
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.
The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2025 and 2024 were as follows:

| Pension Benefits |  | Other Benefits
| Three Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Service cost for benefits earned (1) | $ | 106 |  |  | $ | 99 |  |  | $ | 10 |  |  | $ | 11 |
Interest cost | 252 |  |  | 229 |  |  | 19 |  |  | 18 |
Expected return on plan assets | (264) |  |  | (254) |  |  | (38) |  |  | (35) |
Amortization of prior service (credit) | — |  |  | (1) |  |  | — |  |  | — |
Amortization of net actuarial loss (gain) | 1 |  |  | 1 |  |  | (5) |  |  | (5) |
Net periodic benefit cost | 95 |  |  | 74 |  |  | (14) |  |  | (11) |
Regulatory account transfer (2) | (10) |  |  | (9) |  |  | — |  |  | — |
Total | $ | 85 |  |  | $ | 65 |  |  | $ | (14) |  |  | $ | (11) |

(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery or refund through rates in future periods.

| Pension Benefits |  | Other Benefits
| Six Months Ended June 30,
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Service cost for benefits earned (1) | $ | 212 |  |  | $ | 198 |  |  | $ | 19 |  |  | $ | 21 |
Interest cost | 504 |  |  | 458 |  |  | 37 |  |  | 36 |
Expected return on plan assets | (527) |  |  | (507) |  |  | (75) |  |  | (70) |
Amortization of prior service cost (credit) | (1) |  |  | (2) |  |  | 1 |  |  | 1 |
Amortization of net actuarial loss (gain) | 1 |  |  | 1 |  |  | (11) |  |  | (11) |
Net periodic benefit cost | 189 |  |  | 148 |  |  | (29) |  |  | (23) |
Regulatory account transfer (2) | (20) |  |  | (19) |  |  | — |  |  | — |
Total | $ | 169 |  |  | $ | 129 |  |  | $ | (29) |  |  | $ | (23) |

(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
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Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)
The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) consisted of the following:

| Pension Benefits |  | Other Benefits |  | Available-for-Sale Securities(2) |  | Total
(in millions, net of income tax) | Three Months Ended June 30, 2025
Beginning balance | $ | (35) |  |  | $ | 18 |  |  | $ | 10 |  |  | $ | (7) |
Other comprehensive income before reclassification |  |  |  |  |  |  |
Gain on investments (net of taxes of $0, $0 and $3, respectively) | — |  |  | — |  |  | 7 |  |  | 7 |
Amounts reclassified from other comprehensive income: (1) |  |  |  |  |  |  |
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively) | (1) |  |  | 1 |  |  | — |  |  | — |
Amortization of net actuarial loss (gain) (net of taxes of $0, $2, and $0, respectively) | 1 |  |  | (4) |  |  | — |  |  | (3) |
Regulatory account transfer (net of taxes of $0, $2, and $0, respectively) | 1 |  |  | 3 |  |  | — |  |  | 4 |
Net current period other comprehensive gain | 1 |  |  | — |  |  | 7 |  |  | 8 |
Ending balance | $ | (34) |  |  | $ | 18 |  |  | $ | 17 |  |  | $ | 1 |

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

| Pension Benefits |  | Other Benefits |  | Customer Credit Trust |  | Total
(in millions, net of income tax) | Three Months Ended June 30, 2024
Beginning balance | $ | (28) |  |  | $ | 18 |  |  | $ | 1 |  |  | $ | (9) |
Amounts reclassified from other comprehensive income: (1) |  |  |  |  |  |  |
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively) | — |  |  | 1 |  |  | — |  |  | 1 |
Amortization of net actuarial gain (net of taxes of $0, $2, and $0, respectively) | — |  |  | (4) |  |  | — |  |  | (4) |
Regulatory account transfer (net of taxes of $0, $2, and $0, respectively) | — |  |  | 3 |  |  | — |  |  | 3 |
Net current period other comprehensive loss | — |  |  | — |  |  | — |  |  | — |
Ending balance | $ | (28) |  |  | $ | 18 |  |  | $ | 1 |  |  | $ | (9) |

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
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| Pension Benefits |  | Other Benefits |  | Customer Credit Trust |  | Total
(in millions, net of income tax) | Six Months Ended June 30, 2025
Beginning balance | $ | (35) |  |  | $ | 18 |  |  | $ | 3 |  |  | $ | (14) |
Other comprehensive income before reclassification |  |  |  |  |  |  |
Gain on investments (net of taxes of $0, $0, and $5, respectively) | — |  |  | — |  |  | 14 |  |  | 14 |
Amounts reclassified from other comprehensive income: (1) |  |  |  |  |  |  |
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively) | (1) |  |  | 1 |  |  | — |  |  | — |
Amortization of net actuarial loss (gain) (net of taxes of $0, $3, and $0, respectively) | 1 |  |  | (8) |  |  | — |  |  | (7) |
Regulatory account transfer (net of taxes of $0, $3, and $0, respectively) | 1 |  |  | 7 |  |  | — |  |  | 8 |
Net current period other comprehensive gain | 1 |  |  | — |  |  | 14 |  |  | 15 |
Ending balance | $ | (34) |  |  | $ | 18 |  |  | $ | 17 |  |  | $ | 1 |

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

| Pension Benefits |  | Other Benefits |  | Customer Credit Trust |  | Total
(in millions, net of income tax) | Six Months Ended June 30, 2024
Beginning balance | $ | (28) |  |  | $ | 18 |  |  | $ | 2 |  |  | $ | (8) |
Other comprehensive income before reclassification |  |  |  |  |  |  |
Gain on investments (net of taxes of $0, $0, and $1, respectively) | — |  |  | — |  |  | (1) |  |  | (1) |
Amounts reclassified from other comprehensive income: (1) |  |  |  |  |  |  |
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively) | (1) |  |  | 1 |  |  | — |  |  | — |
Amortization of net actuarial gain (net of taxes of $0, $3, and $0, respectively) | — |  |  | (8) |  |  | — |  |  | (8) |
Regulatory account transfer (net of taxes of $0, $3, and $0, respectively) | 1 |  |  | 7 |  |  | — |  |  | 8 |
Net current period other comprehensive loss | — |  |  | — |  |  | (1) |  |  | (1) |
Ending balance | $ | (28) |  |  | $ | 18 |  |  | $ | 1 |  |  | $ | (9) |

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Accounting Standards Issued But Not Yet Adopted
Income Taxes
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and disaggregation of income taxes paid by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. There is no significant impact on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures. PG&E Corporation and the Utility will adopt this new ASU in its Form 10-K for the year ending December 31, 2025.
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Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
Induced Conversions of Convertible Debt Instruments
In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Noncurrent regulatory assets are comprised of the following:

| Balance at
(in millions) | June 30, 2025 |  | December 31, 2024
Pension benefits | $ | 682 |  |  | $ | 673 |
Environmental compliance costs | 1,109 |  |  | 1,172 |
Price risk management | 104 |  |  | 167 |
Catastrophic event memorandum account | 762 |  |  | 742 |
Wildfire-related accounts | 1,721 |  |  | 1,697 |
Deferred income taxes | 5,242 |  |  | 4,771 |
Financing costs | 209 |  |  | 216 |
SB 901 securitization | 5,139 |  |  | 5,194 |
General rate case memorandum accounts | 78 |  |  | 95 |
Other | 807 |  |  | 834 |
Total noncurrent regulatory assets | $ | 15,853 |  |  | $ | 15,561 |

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Regulatory Liabilities
Noncurrent regulatory liabilities are comprised of the following:

| Balance at
(in millions) | June 30, 2025 |  | December 31, 2024
Cost of removal obligations | $ | 9,265 |  |  | $ | 8,943 |
Public purpose programs | 1,192 |  |  | 1,112 |
Employee benefit plans | 1,098 |  |  | 1,088 |
Transmission tower wireless licenses | 282 |  |  | 306 |
SFGO sale | 40 |  |  | 79 |
SB 901 securitization | 6,145 |  |  | 6,295 |
Wildfire self-insurance | 807 |  |  | 804 |
Other | 1,042 |  |  | 790 |
Total noncurrent regulatory liabilities | $ | 19,871 |  |  | $ | 19,417 |

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

| Balance at
(in millions) | June 30, 2025 |  | December 31, 2024
Electric distribution | $ | 1,705 |  |  | $ | 1,591 |
Electric transmission | 113 |  |  | 117 |
Gas distribution and transmission | 119 |  |  | 387 |
Energy procurement | 1,285 |  |  | 1,066 |
Public purpose programs | 207 |  |  | 162 |
Wildfire-related accounts | 640 |  |  | 979 |
Insurance premium costs | — |  |  | 38 |
Residential uncollectibles balancing accounts | 146 |  |  | 260 |
Catastrophic event memorandum account | 265 |  |  | 500 |
General rate case memorandum accounts | 557 |  |  | 1,113 |
Other | 620 |  |  | 1,014 |
Total regulatory balancing accounts receivable | $ | 5,657 |  |  | $ | 7,227 |

| Balance at
(in millions) | June 30, 2025 |  | December 31, 2024
Electric transmission | $ | 477 |  |  | $ | 883 |
Gas distribution and transmission | 61 |  |  | 72 |
Energy procurement | 520 |  |  | 329 |
Public purpose programs | 563 |  |  | 882 |
SFGO sale | 42 |  |  | 93 |
Wildfire-related accounts | 291 |  |  | 337 |
Nuclear decommissioning adjustment mechanism | 10 |  |  | 23 |
Other | 552 |  |  | 550 |
Total regulatory balancing accounts payable | $ | 2,516 |  |  | $ | 3,169 |

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.
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NOTE 4: DEBT
Credit Facilities and Term Loans
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2025:

(in millions) | Termination Date |  | Maximum Facility Limit |  | Loans Outstanding |  | Letters of Credit Outstanding |  | Facility Availability |
Utility revolving credit facility | June 2030 |  | $ | 5,400 |  | (1) | $ | — |  |  | $ | (388) |  |  | $ | 5,012 |  |
Utility Receivables Securitization Program (2) | June 2027 |  | 1,500 |  | (3) | (190) |  |  | — |  |  | 1,310 |  | (3)
PG&E Corporation revolving credit facility | June 2028 |  | 650 |  |  | — |  |  | — |  |  | 650 |  |
Total credit facilities |  |  | $ | 7,550 |  |  | $ | (190) |  |  | $ | (388) |  |  | $ | 6,972 |  |

(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 to April 10, 2026. The loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.
On June 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 up of to $250 million, subject to the satisfaction of certain terms and conditions.
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 expects to use the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount 3.15% First Mortgage Bonds due January 1, 2026.
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Convertible Notes
On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”).
As of both June 30, 2025 and December 31, 2024, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.13 billion, with unamortized debt issuance costs of $17 million and $20 million, respectively, in Long-term debt. For the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected the total interest expense of approximately $23 million and $46 million, respectively. For the three and six months ended June 30, 2024, the total interest expense recorded was immaterial to the Condensed Consolidated Statements of Income.
For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K. As of June 30, 2025, none of the conditions allowing holders of the Convertible Notes to convert had been met.
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 fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the six months ended June 30, 2025 and 2024.
Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $664 million was contributed on March 31, 2025. 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 Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2025, the Utility recorded $63 million and $139 million for amortization of the regulatory asset and liability, respectively, in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2024, the Utility recorded $82 million and $162 million for amortization of the regulatory asset and liability, respectively, in the Condensed 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 | (55) |  |  | (19) |
Balance at June 30 | $ | 5,139 |  |  | $ | 5,230 |

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| SB 901 securitization regulatory liability |
(in millions) | 2025 |  | 2024 |
Balance at January 1 | $ | (6,295) |  |  | $ | (6,628) |  |
Amortization | 194 |  | 180 |
Additions(1) | (44) |  |  | (9) |  |
Balance at June 30 | $ | (6,145) |  |  | $ | (6,457) |  |

(1) Includes $44 million and $9 million of returns on investments in the customer credit trust expected to be credited to customers for the six months ended June 30, 2025 and 2024, respectively.
NOTE 6: EQUITY
Dividends
Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s and the Utility’s Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant.
Utility
On each of November 29, 2024 and February 20, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 18 and May 15, 2025, to holders of record as of January 31 and April 30, 2025. On May 22, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on August 15, 2025, to holders of record as of July 31, 2025.
On each of February 20 and May 22, 2025, the Board of Directors of the Utility declared common stock dividends of $575 million, which were paid to PG&E Corporation on March 18 and May 30, 2025, respectively.
PG&E Corporation
On each of November 29, 2024, February 20, and May 22, 2025, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.025 per share, each declaration totaling $55 million, which were paid on January 15, April 15, and July 15, 2025, to holders of record as of December 31, 2024, March 31, and June 30, 2025, respectively.
On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share, totaling $23 million, which was paid on February 27, 2025, to holders of record as of February 14, 2025. On February 20, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, which was paid on May 29, 2025, to holders of record as of May 15, 2025. On May 22, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, payable on September 1, 2025, to holders of record as of August 15, 2025.
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NOTE 7: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(in millions, except per share amounts) | 2025 |  | 2024 |  | 2025 |  | 2024
Income available for common shareholders | $ | 521 |  |  | $ | 520 |  |  | $ | 1,128 |  |  | $ | 1,252 |
Weighted average common shares outstanding, basic(1) | 2,198 |  |  | 2,137 |  |  | 2,196 |  |  | 2,136 |
Add incremental shares from assumed conversions: |  |  |  |  |  |  |
Employee share-based compensation | 5 |  |  | 5 |  |  | 5 |  |  | 5 |
Weighted average common shares outstanding, diluted | 2,203 |  |  | 2,142 |  |  | 2,201 |  |  | 2,141 |
Total income per common share, diluted | $ | 0.24 |  |  | $ | 0.24 |  |  | $ | 0.51 |  |  | $ | 0.58 |

(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 amount of options and securities that were antidilutive. For the three and six months ended June 30, 2025, the calculation of outstanding common shares on a diluted basis excluded the impacts of the mandatory convertible preferred stock, which was antidilutive.
NOTE 8: 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 Condensed 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 Condensed 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 Condensed 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 Condensed Consolidated Balance Sheets at fair value.
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Volume of Derivative Activity
The volumes of the Utility’s outstanding derivatives were as follows:

|  |  |  | Contract Volume at
Underlying Product |  | Instruments |  | June 30, 2025 |  | December 31, 2024
Natural Gas (1) (MMBtus (2)) |  | Forwards, futures, and swaps |  | 293,476,836 |  |  | 179,257,247 |
|  | Options |  | 53,165,000 |  |  | 37,717,500 |
Electricity (MWh) |  | Forwards, futures, and swaps |  | 8,729,140 |  |  | 8,576,078 |
|  | Options |  | 1,878,000 |  |  | 1,663,200 |
|  | Congestion Revenue Rights (3) |  | 103,445,748 |  |  | 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 June 30, 2025, the Utility’s outstanding derivative balances were as follows:

| Commodity Risk
(in millions) | Gross Derivative Balance |  | Netting |  | Cash Collateral |  | Total Derivative Balance
Current assets – other | $ | 162 |  |  | $ | (11) |  |  | $ | 12 |  |  | $ | 163 |
Noncurrent assets – other | 223 |  |  | — |  |  | — |  |  | 223 |
Current liabilities – other | (105) |  |  | 11 |  |  | — |  |  | (94) |
Noncurrent liabilities – other | (104) |  |  | — |  |  | — |  |  | (104) |
Total commodity risk | $ | 176 |  |  | $ | — |  |  | $ | 12 |  |  | $ | 188 |

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

| Commodity Risk
(in millions) | Gross Derivative Balance |  | Netting |  | Cash Collateral |  | Total Derivative Balance
Current assets – other | $ | 186 |  |  | $ | (16) |  |  | $ | — |  |  | $ | 170 |
Other 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 Condensed 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 June 30, 2025, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
NOTE 9: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
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•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 June 30, 2025
(in millions) | Level 1 |  | Level 2 |  | Level 3 |  | Netting (1) |  | Total
Assets: |  |  |  |  |  |  |  |  |
Short-term investments | $ | 338 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 338 |
Pacific Energy Risk Solutions, LLC |  |  |  |  |  |  |  |  |
Short-term investments | 979 |  |  | — |  |  | — |  |  | — |  |  | 979 |
Total Pacific Energy Risk Solutions, LLC | 979 |  |  | — |  |  | — |  |  | — |  |  | 979 |
Nuclear decommissioning trusts |  |  |  |  |  |  |  |  |
Short-term investments | 46 |  |  | — |  |  | — |  |  | — |  |  | 46 |
Global equity securities | 2,433 |  |  | — |  |  | — |  |  | — |  |  | 2,433 |
Fixed-income securities | 1,277 |  |  | 1,051 |  |  | — |  |  | — |  |  | 2,328 |
Assets measured at NAV | — |  |  | — |  |  | — |  |  | — |  |  | 24 |
Total nuclear decommissioning trusts (2) | 3,756 |  |  | 1,051 |  |  | — |  |  | — |  |  | 4,831 |
Customer credit trust |  |  |  |  |  |  |  |  |
Short-term investments | 16 |  |  | — |  |  | — |  |  | — |  |  | 16 |
Global equity securities | 473 |  |  | — |  |  | — |  |  | — |  |  | 473 |
Fixed-income securities | 88 |  |  | 358 |  |  | — |  |  | — |  |  | 446 |
Total customer credit trust | 577 |  |  | 358 |  |  | — |  |  | — |  |  | 935 |
Price risk management instruments (Note 8) |  |  |  |  |  |  |  |  |
Electricity | — |  |  | 48 |  |  | 312 |  |  | 3 |  |  | 363 |
Gas | — |  |  | 25 |  |  | — |  |  | (2) |  |  | 23 |
Total price risk management instruments | — |  |  | 73 |  |  | 312 |  |  | 1 |  |  | 386 |
Rabbi trusts |  |  |  |  |  |  |  |  |
Short-term investments | 112 |  |  | — |  |  | — |  |  | — |  |  | 112 |
Global equity securities | 4 |  |  | — |  |  | — |  |  | — |  |  | 4 |
Life insurance contracts | — |  |  | 66 |  |  | — |  |  | — |  |  | 66 |
Total rabbi trusts | 116 |  |  | 66 |  |  | — |  |  | — |  |  | 182 |
Long-term disability trust |  |  |  |  |  |  |  |  |
Short-term investments | 4 |  |  | — |  |  | — |  |  | — |  |  | 4 |
Assets measured at NAV | — |  |  | — |  |  | — |  |  | — |  |  | 129 |
Total long-term disability trust | 4 |  |  | — |  |  | — |  |  | — |  |  | 133 |
TOTAL ASSETS | $ | 5,770 |  |  | $ | 1,548 |  |  | $ | 312 |  |  | $ | 1 |  |  | $ | 7,784 |
Liabilities: |  |  |  |  |  |  |  |  |
Price risk management instruments (Note 8) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 24 |  |  | $ | 176 |  |  | $ | (5) |  |  | $ | 195 |
Gas | — |  |  | 9 |  |  | — |  |  | (6) |  |  | 3 |
TOTAL LIABILITIES | $ | — |  |  | $ | 33 |  |  | $ | 176 |  |  | $ | (11) |  |  | $ | 198 |

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $809 million primarily related to deferred taxes on appreciation of investment value.
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| 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 8) |  |  |  |  |  |  |  |  |
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 8) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 37 |  |  | $ | 248 |  |  | $ | (6) |  |  | $ | 279 |
Gas | — |  |  | 34 |  |  | — |  |  | (10) |  |  | 24 |
TOTAL LIABILITIES | $ | — |  |  | $ | 71 |  |  | $ | 248 |  |  | $ | (16) |  |  | $ | 303 |

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.
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 six months ended June 30, 2025 or 2024.
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Trust Assets
Assets Measured at Fair Value
In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets, customer credit trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds classified as Level 1.
Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, credit securities, and asset-backed securities.
Pacific Energy Risk Solutions, LLC
Investments held in Pacific Energy Risk Solutions, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.
Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.
Level 3 Measurements and Uncertainty Analysis
Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
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Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.

|  | Fair Value (in millions) |  |  |  |  |  |
|  | At June 30, 2025 |  | Valuation Technique |  | Unobservable Input |  |
Fair Value Measurement |  | Assets |  | Liabilities |  |  |  | Range (1)/Weighted-Average Price (2)
Congestion revenue rights |  | $ | 257 |  |  | $ | 100 |  |  | Market approach |  | CRR auction prices |  | $ (57) - 54 / 2
Power purchase agreements |  | $ | 55 |  |  | $ | 76 |  |  | Discounted cash flow |  | Forward prices |  | $ 16 - 110 / 62

(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

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

(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2025 and 2024, respectively:

| Price Risk Management Instruments
(in millions) | 2025 |  | 2024
Asset balance as of April 1 | $ | 126 |  |  | $ | 145 |
Net realized and unrealized gains (losses): |  |  |
Included in regulatory assets and liabilities or balancing accounts (1) | 10 |  |  | 13 |
Asset balance as of June 30 | $ | 136 |  |  | $ | 158 |

(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.

| 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) | 9 |  |  | (33) |
Asset balance as of June 30 | $ | 136 |  |  | $ | 158 |

(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 June 30, 2025 and December 31, 2024, as they are short-term in nature.
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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 June 30, 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) | $ | 5,352 |  |  | $ | 5,490 |  |  | $ | 5,358 |  |  | $ | 5,829 |
Utility | 38,162 |  |  | 34,319 |  |  | 37,812 |  |  | 34,532 |

(1) As of June 30, 2025, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes was $2.1 billion.
Nuclear Decommissioning Trust Investments
The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions) | Amortized Cost |  | Total Unrealized Gains |  | Total Unrealized Losses |  | Total Fair Value
As of June 30, 2025 |  |  |  |  |  |  |
Nuclear decommissioning trusts |  |  |  |  |  |  |
Short-term investments | $ | 46 |  |  | $ | — |  |  | $ | — |  |  | $ | 46 |
Global equity securities | 372 |  |  | 2,091 |  |  | (6) |  |  | 2,457 |
Fixed-income securities | 2,341 |  |  | 44 |  |  | (57) |  |  | 2,328 |
Total (1) | $ | 2,759 |  |  | $ | 2,135 |  |  | $ | (63) |  |  | $ | 4,831 |
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 $809 million and $747 million as of June 30, 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) | June 30, 2025
Less than 1 year | $ | 13 |
1–5 years | 780 |
5–10 years | 556 |
More than 10 years | 979 |
Total maturities of fixed-income securities | $ | 2,328 |

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

| Three Months Ended June 30, |  | Six Months Ended June 30, |
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ | 501 |  |  | $ | 587 |  |  | $ | 779 |  |  | $ | 1,044 |  |
Gross realized gains on securities | 4 |  |  | 70 |  |  | 6 |  | 111 |  |
Gross realized losses on securities | (11) |  |  | (19) |  |  | (17) |  |  | (30) |  |

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

(in millions) | Amortized Cost |  | Total Unrealized Gains |  | Total Unrealized Losses |  | Total Fair Value
As of June 30, 2025 |  |  |  |  |  |  |
Customer credit trust |  |  |  |  |  |  |
Short-term investments | $ | 16 |  |  | $ | — |  |  | $ | — |  |  | $ | 16 |
Global equity securities | 397 |  |  | 80 |  |  | (4) |  |  | 473 |
Fixed-income securities | 444 |  |  | 4 |  |  | (2) |  |  | 446 |
Total | $ | 857 |  |  | $ | 84 |  |  | $ | (6) |  |  | $ | 935 |
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) | June 30, 2025
Less than 1 year | $ | — |
1–5 years | 116 |
5–10 years | 63 |
More than 10 years | 267 |
Total maturities of fixed-income securities | $ | 446 |

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

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Proceeds from sales and maturities of customer credit trust investments | $ | 97 |  |  | $ | 93 |  |  | $ | 196 |  |  | $ | 174 |  |  |
Gross realized gains on securities | 2 |  |  | — |  |  | 5 |  | 8 |  |
Gross realized losses on securities | (8) |  |  | (1) |  |  | (11) |  |  | (2) |  |  |

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NOTE 10: WILDFIRE-RELATED CONTINGENCIES
Liability Overview
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.
Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility.
Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.
PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further complaints. However, the applicable statutes of limitations have expired for the 2019 Kincade fire and 2021 Dixie fire, except for the 2021 Dixie fire USFS statute of limitations, which expires in 2027. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.
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If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.
If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire 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 June 30, 2025.

Payments (in millions) |
2019 Kincade Fire | $ | 1,177 |
2021 Dixie Fire | 1,624 |
2022 Mosquito Fire | 63 |
Total at June 30, 2025 | $ | 2,864 |

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 July 23, 2025, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 2,989 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024, the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.
PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation. The court previously scheduled a trial on their claims. Since then, the parties entered into a settlement agreement, and the court vacated the trial date on April 23, 2025.
On October 11, 2022, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.
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Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 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 the first quarter of 2025, PG&E Corporation and the Utility recorded additional charges of $50 million. 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 the second quarter of 2025 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 | (219) |
Balance at June 30, 2025 | $ | 148 |

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.
2021 Dixie Fire
According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.
On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, through its ongoing investigation, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.
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As of July 23, 2025, PG&E Corporation and the Utility are aware of approximately 184 complaints on behalf of at least 8,894 individual plaintiffs related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025.
The Collins Pine Company and a group of timber companies filed a complaint against PG&E Corporation and the Utility on April 10, 2024. PG&E Corporation and the Utility answered this complaint on May 28, 2024.
Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer 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 July 30, 2025, 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. After PG&E Corporation and the Utility demurred to the putative class complaint, the court issued an order abating the case unless the plaintiffs amended the complaint, which the plaintiffs did on February 12, 2025. On March 18, 2025, PG&E Corporation and the Utility filed an answer, and on April 18, 2025 filed an amended answer. On April 28, 2025, the plaintiffs filed a demurrer and a motion to strike PG&E Corporation and the Utility’s answer. Those motions are set for hearing on October 1, 2025. The court set December 1, 2025 as the deadline for the plaintiffs to move for class certification.
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 the second quarter of 2025 of $150 million for an aggregate liability of $2.075 billion (before available recoveries).
PG&E Corporation’s and the Utility’s accrued estimated losses of $2.075 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.
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The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2024.

Loss Accrual (in millions) |
Balance at December 31, 2024 | $ | 567 |
Accrued Losses | 150 |
Payments | (265) |
Balance at June 30, 2025 | $ | 452 |

As of June 30, 2025, the Utility recorded an insurance receivable of $523 million for probable insurance recoveries in connection with the 2021 Dixie fire.
The Utility recorded an aggregate Wildfire Fund receivable of $1.075 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $445 million as of June 30, 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 under AB 1054” below. As of June 30, 2025, the Utility also recorded a $95 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 $526 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 July 23, 2025, PG&E Corporation and the Utility are aware of approximately 26 complaints on behalf of at least 2,716 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. 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. On April 24, 2024, PG&E Corporation and the Utility filed cross-complaints against PCWA, alleging that conduct by PCWA was a substantial cause of the 2022 Mosquito fire. The cross-complaints seek property damages, indemnification, attorneys’ fees, and other damages. The court has set individual claimant bellwether trial dates for November 7, 2025 and 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 until June 5, 2026.
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Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including 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 insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during the second quarter of 2025 of $150 million for an aggregate liability of $250 million (before available insurance).
PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties 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 or state agencies for state or federal fire suppression costs and damages related to federal land, or (iv) any other amounts that are not reasonably estimable.
As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.
The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2024.

Loss Accrual (in millions) |
Balance at December 31, 2024 | $ | 82 |
Accrued Losses | 150 |
Payments | (45) |
Balance at June 30, 2025 | $ | 187 |

As of June 30, 2025, the Utility recorded an insurance receivable of $251 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of June 30, 2025, the Utility also recorded a $6 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 June 30, 2025 are:

Potential Recovery Source (in millions) | 2021 Dixie fire |  | 2022 Mosquito fire
Insurance | $ | 523 |  |  | $ | 251 |
FERC TO rates | 95 |  |  | 6 |
WEMA | 526 |  |  | 54 |
Wildfire Fund | 1,075 |  |  | — |
Probable recoveries at June 30, 2025 (1) | $ | 2,219 |  |  | $ | 311 |

(1) Includes legal costs of $125 million and $54 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of June 30, 2025.
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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 June 30, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $523 million and $251 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 Condensed 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 |  |  | (5) |  |  | 161 |  |  | 156 |
Reimbursements |  |  | — |  |  | (29) |  |  | (29) |
Balance at June 30, 2025 |  |  | $ | 22 |  |  | $ | 222 |  |  | $ | 244 |

Regulatory Recovery
Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the Utility’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”
The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.
FERC TO Rates
The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of June 30, 2025, the Utility recorded reductions of $95 million and $6 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.
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WEMA
The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of June 30, 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 $526 million and $54 million, respectively, as regulatory assets in the WEMA.
Wildfire Fund under AB 1054
On July 12, 2019, AB 1054 became law. The law provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate arising from wildfires in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of June 30, 2025 reflects an expectation that the Coverage Year will be based on the calendar year.
Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. This reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the IOU’s electric transmission and distribution rate base in the year of the prudency determination. A utility would not be required to reimburse the Wildfire Fund for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Utility, the disallowance cap would be approximately $4.7 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, resulting in a draw-down of the Wildfire Fund.
Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 11, 2024, the OEIS approved the Utility’s 2024 application and issued the Utility’s 2024 safety certification.
The Wildfire Fund and disallowance cap will be terminated when the amounts in the fund are exhausted. The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating electric IOUs for a 10-year period.
The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. AB 1054 authorizes the reimbursement of funds where a participating utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.
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As of June 30, 2025, PG&E Corporation and the Utility recorded $625 million and $5 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2024:

Wildfire Fund Receivable (in millions) | 2021 Dixie fire
Balance at December 31, 2024 | $ | 756 |
Accrued Wildfire Fund recoveries | 150 |
Claims paid by Wildfire Fund | (276) |
Balance at June 30, 2025 | $ | 630 |

For more information, see Note 2 above.
Wildfire-Related Securities Litigation
As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”
Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount due to the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such settlement.
Wildfire-Related Securities Claims in District Court
In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.
On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.
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On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain former officers and directors, and the underwriters. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint.
On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation.
On August 21, 2024, the District Court entered an order setting a briefing schedule for renewed motions to dismiss the third amended complaint. Opening briefs were filed on October 24, 2024, opposition briefs were filed December 20, 2024, and reply briefs were filed January 31, 2025.
Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process
PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from the trading of debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).
While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, these defenses may not prevail and proceeds from any insurance may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows:
•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and
•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.
PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. Such claims could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.
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On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.
PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.
Indemnification Obligations
To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions.
PG&E Corporation and the Utility additionally may have indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.
Butte County District Attorney’s Office Investigation into the 2018 Camp Fire
Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.
On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s Office to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility pleaded guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).
On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to November 14, 2025.
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NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
CPUC and FERC Matters
2022 WMCE Interim Rate Relief Subject to Refund
On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in the 2022 WMCE application reflect costs related to wildfire mitigation and certain catastrophic events, as well as the implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.
The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision for such requested rate relief. Cost recovery requested in the 2022 WMCE application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.
2023 WMCE Interim Rate Relief Subject to Refund
On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 WMCE application”). The costs addressed in 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 that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in the 2023 WMCE application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.
Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund
On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.
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The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.
On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.
Other Matters
PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters totaled $86 million and $74 million as of June 30, 2025 and December 31, 2024, respectively. These amounts were included in Other current liabilities on the Condensed 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 10 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.
Tax Matters
PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. On June 4, 2024, the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. As a result, in the year ended December 31, 2024, PG&E Corporation determined that it is no longer more likely than not that its deduction related to a portion of the customer bill credits would ultimately be sustained. Accordingly, PG&E Corporation has decreased its Income tax benefit by $70 million in the year ended December 31, 2024 related to state and federal income taxes. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.
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Environmental Remediation Contingencies
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

| Balance at
(in millions) | June 30, 2025 |  | December 31, 2024
Topock natural gas compressor station | $ | 339 |  |  | $ | 294 |
Hinkley natural gas compressor station | 97 |  |  | 97 |
Former MGP sites owned by the Utility or third parties (1) | 764 |  |  | 782 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) | 74 |  |  | 76 |
Fossil fuel-fired generation facilities and sites (3) | 18 |  |  | 18 |
Total environmental remediation liability | $ | 1,292 |  |  | $ | 1,267 |

(1) Primarily driven by the following sites: San Francisco Beach Street, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal Landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.
The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the United States Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances. The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the California Environmental Protection Agency, Department of Toxic Substances Control (“DTSC”), several California regional water quality control boards, and various other federal, state, and local agencies.
The Utility’s environmental remediation liability as of June 30, 2025, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of June 30, 2025, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.
Natural Gas Compressor Station Sites
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
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Topock Site
The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $203 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.
Hinkley Site
The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take action to meet interim cleanup targets. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $136 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.
Former Manufactured Gas Plants
Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $576 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.
Utility-Owned Generation Facilities and Third-Party Disposal Sites
Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $76 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.
Fossil Fuel-Fired Generation Sites
In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $15 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance
The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.
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NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for DCPP. For the 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. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.
Purchase Commitments
In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2024, the Utility had undiscounted future expected obligations of approximately $33 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K. During the six months ended June 30, 2025, several power purchase agreements that were previously signed by the Utility were approved by the CPUC and met major operational milestones, resulting in additional undiscounted future expected obligations of approximately $2.6 billion over the next 25 years.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. See the section above entitled “Risk Management Activities” in Part I, Item 2 and in Notes 8 and 9 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.
ITEM 4. CONTROLS AND PROCEDURES
As required by Rules 13a-15(b) or 15d-15(b) under the Exchange Act, PG&E Corporation and the Utility carried out an evaluation, under the supervision and with the participation of management, including their respective principal executive officers and principal financial officers, of the effectiveness of the design and operation of their disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. No matter how well designed and operated, disclosure controls and procedures can provide only reasonable, rather than absolute, assurance of achieving the desired control objectives. Based on the foregoing, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers concluded that such controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
There were no changes in internal control over financial reporting that occurred during the three months ended June 30, 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.
PART II. OTHER INFORMATION
ITEM 1. 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, including updates to information reported under Item 3: “Legal Proceedings” of the 2024 Form 10-K, see Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and Part I, Item 2: “Litigation Matters.”
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Each of PG&E Corporation and the Utility has elected to disclose environmental proceedings described in Item 103(c)(3)(iii) of Regulation S-K unless it reasonably believes that such proceeding will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than $1 million.
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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 5. OTHER INFORMATION
During the three months ended June 30, 2025, no director or officer of PG&E Corporation or the Utility adopted or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
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 under the Exchange Act or may constitute “non-Rule 10b5-1 trading arrangements” (as defined in Item 408(c) of Regulation S-K).
ITEM 6. EXHIBITS
EXHIBIT INDEX

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 dated 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)

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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. 1-23448), Exhibit 3.2)
3.5 |  | Bylaws of Pacific Gas and Electric Company, Amended and Restated as of December 12, 2024 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 12, 2024 (File No. 1-2348), Exhibit 3.2)
4.1 |  | Twenty-Ninth Supplemental Indenture, dated as of June 4, 2025, 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 2, 2025 (File No. 1-2348), Exhibit 4.1)
10.1 |  | 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 dated April 24, 2025 (File No. 1-2348), Exhibit 10.2)
10.2 |  | Amendment No. 5 to Credit Agreement, dated as of June 23, 2025, among PG&E Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 23, 2025 (File No. 1-2348), Exhibit 10.2)
10.3 |  | Amendment No. 5 to Credit Agreement, dated as of June 23, 2025, among Pacific Gas and Electric Company, the lenders party thereto, 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)
10.4 |  | 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
10.5 | * | PG&E Corporation 2021 Long-Term Incentive Plan, as amended effective as of May 22, 2025
10.6 | * | Form of Restricted Stock Unit Agreement for 2025 grants to Non-Employee Directors under the PG&E Corporation 2021 Long-Term Incentive Plan
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
31.2 |  | Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1 | ** | Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2 | ** | Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 200 2
101.INS |  | XBRL Instance Document
101.SC |  | XBRL Taxonomy Extension Schema Document
101.CA |  | XBRL Taxonomy Extension Calculation Linkbase Document
101.LA |  | XBRL Taxonomy Extension Labels Linkbase Document
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document
101.DE |  | 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.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

| PG&E CORPORATION
| /s/ CAROLYN J. BURKE
| Carolyn J. Burke Executive Vice President and Chief Financial Officer (duly authorized officer and principal financial officer)

| PACIFIC GAS AND ELECTRIC COMPANY
| /s/ STEPHANIE N. WILLIAMS
| Stephanie N. Williams Vice President, Chief Financial Officer, and Controller (duly authorized officer and principal financial officer)

Dated: July 30, 2025
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