PG&E PCG Form 10-Q filing Q2 FY2026

• SEC Form 10-Q Reference Number

• RESULTS OF OPERATIONS
• LIQUIDITY AND FINANCIAL RESOURCES
• REGULATORY MATTERS
• LEGISLATIVE INITIATIVES
• LITIGATION AND OTHER 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

OTHER INFORMATION Part II, Item 5

EXHIBITS Part II, Item 6

SIGNATURES

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

Continuation Account the account established statewide by SB 254 that expands the existing Wildfire Fund

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

GAAP United States Generally Accepted Accounting Principles

GRC general rate case

HSMA Hazardous Substance Memorandum Account

IOUs investor-owned utility(ies)

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

MWh one megawatt continuously for one hour

NAV net asset value

NEIL Nuclear Electric Insurance Limited, a mutual insurer owned by utilities with nuclear facilities

NRC Nuclear Regulatory Commission

OEIS Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)

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

PD proposed decision

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

SCE Edison International and Southern California Edison Company

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)

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

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 2025 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 2025 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.

PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements are available free of charge on PG&E Corporation’s website, www.pgecorp.com, as promptly as practicable after they are filed with, or furnished to, the SEC. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC located at http://www.sec.gov. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Wildfire and Safety” and “News & Events: Events & Presentations” pages, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on PG&E Corporation’s website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the addresses of this website solely for the information of investors and do not intend the address to be an active link.

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

See accompanying Notes to the Condensed Consolidated Financial Statements.

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 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 which are, in the opinion of the management, of a normal recurring nature and necessary to a fair statement of the results for the interim periods presented. The information as of December 31, 2025 in the Condensed Consolidated Balance Sheets included in this Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2025 Form 10-K. This Form 10-Q should be read in conjunction with the 2025 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.

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.

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

(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, 2026, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

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

Expected credit losses of $30 million and $119 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, 2026, respectively. For the three and six months ended June 30, 2025, expected credit losses were $141 million and $241 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, 2026, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $123 million and $86 million, respectively. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. The RUBA current balancing account balance decreased from December 31, 2025 to June 30, 2026 primarily due to the annual electric and gas rate true-up, which allows the Utility to recover approximately $278 million in undercollections from residential customers in 2026.

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. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of June 30, 2026, 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 six months ended June 30, 2026 and 2025. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final proceeds were received in 2024, and no further disbursements will be made.

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

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

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, 2026, the Condensed Consolidated Statements of Income reflected $22 million and $31 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 $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, 2026, the amount recorded as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP was immaterial. During the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $16 million and $57 million, respectively, as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The 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, 2026 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2026 and December 31, 2025, the SPV had net accounts receivable of $3.3 billion and $3.2 billion, respectively, and outstanding borrowings of $1.8 billion, 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, 2026 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of June 30, 2026 and December 31, 2025, PG&E Recovery Funding LLC had outstanding borrowings of $3.0 billion and $3.1 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, 2026 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate of $7.5 billion of senior secured recovery bonds. As of June 30, 2026 and December 31, 2025, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.0 billion and $7.1 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.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of June 30, 2026, 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, 2026, it did not consolidate any of them.

Contributions to the Wildfire Fund and the Continuation Account

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

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

The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

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

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable. On February 18, 2026, SCE disclosed in its Annual Report on Form 10-K for the year ended December 31, 2025 that it has entered into settlements with insurance claimants and claimants under its Wildfire Recovery Compensation Program related to the Eaton fire. As of March 31, 2026, SCE had recorded $1.3 billion in losses related to these settlements. SCE also recorded expected recoveries from the Wildfire Fund of $295 million. As a result, PG&E Corporation and the Utility accelerated the amortization of the Wildfire Fund asset during the three and six months ended June 30, 2026 as described below.

As of June 30, 2026, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $379 million in Other noncurrent liabilities, $291 million in Current assets - Wildfire Fund asset, and $3.5 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $126 million and $109 million, respectively. During the six months ended June 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $228 million and $185 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.

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

For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 below.

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, 2026 and 2025 were as follows:

(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.

(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.

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:

(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 self-insurance.

(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 self-insurance.

(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 self-insurance.

(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 self-insurance.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Recently Adopted Accounting Standards

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU became effective for PG&E Corporation and the Utility on January 1, 2026. The adoption of this ASU did not have an immediate impact and is not expected to have a significant impact in future periods on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures.

Accounting Standards Issued But Not Yet Adopted

Disaggregation of Income Statement Expenses

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

Intangibles – Goodwill and Other – Internal Use Software

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

Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818), which establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their financial statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Noncurrent regulatory assets are comprised of the following:

Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:

Regulatory Balancing Accounts

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

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

NOTE 4: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2026:

(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 June 22, 2026, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 20, 2031, (ii) increase the aggregate commitments from $5.4 billion to $6.25 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2026, the Utility and the SPV amended the existing $1.75 billion Receivables Securitization Program to extend the scheduled termination date from June 25, 2027 to June 26, 2028.

PG&E Corporation

On June 22, 2026, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2029, (ii) modify both the interest rate pricing grid and commitment fee pricing grid and (iii) add collateral release terms.

Long-Term Debt Issuances and Redemptions

Utility

On February 20, 2026, the Utility completed the sale of (i) $400 million aggregate principal amount of 6.100% first mortgage bonds due 2029, (ii) $1.0 billion aggregate principal amount of 5.200% first mortgage bonds due 2036 and (iii) $800 million aggregate principal amount of 6.000% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of $600 million aggregate principal amount of 2.95% first mortgage bonds due March 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 3, 2026, the Utility completed the sale of (i) $800 million aggregate principal amount of 5.050% first mortgage bonds due 2031, (ii) $800 million aggregate principal amount of 5.600% first mortgage bonds due 2036 and (iii) $600 million aggregate principal amount of 6.300% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of short-term debt, including borrowings outstanding under its revolving credit facility. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

PG&E Corporation

On February 19, 2026, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056. These notes initially bear interest at the rate of 6.850% per annum, and beginning September 15, 2031 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.225% (but not below 6.850%). PG&E Corporation used the net proceeds for general corporate purposes, including repayment of indebtedness.

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, 2026 and December 31, 2025, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion, with unamortized debt issuance costs of $10 million and $13 million, respectively, included in Long-term debt. For both the three and six months ended June 30, 2026 and 2025, the Condensed Consolidated Statements of Income reflected total interest expense of approximately $23 million and $46 million, respectively.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. As of June 30, 2026, 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 customer credit trust (see Note 9 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the six months ended June 30, 2026 and 2025.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. As of December 31, 2025, the Utility had made all required upfront contributions. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2026, the Utility recorded $82 million and $162 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, 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.

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

(1) Includes $3 million and $44 million of returns on investments in the customer credit trust expected to be credited to customers for each of the six months ended June 30, 2026 and 2025, respectively.

NOTE 6: EQUITY

Dividends

Subject to the dividend restrictions as described in Notes 6 and 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 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.

The following table summarizes the dividends paid or declared by PG&E Corporation and the Utility in 2026:

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

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the Income available for common shareholders, basic, by the weighted average number of common shares outstanding, basic. PG&E Corporation’s diluted EPS is calculated by dividing the income available for common shareholders, diluted, by the weighted average number of common shares outstanding, diluted. 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:

(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.

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.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

(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, 2026, the Utility’s outstanding derivative balances were as follows:

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:

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. One major credit agency continues to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of June 30, 2026, 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, self-insurance assets, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

• Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
• Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
• Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

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

(2) Includes approximately $1 billion and $144 million held in the entities for wildfire and non-wildfire self-insurance, respectively.

(3) Represents amount before deducting $904 million primarily related to deferred taxes on appreciation of investment value.

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

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

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

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, 2026 or 2025.

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.

Self-insurance investments

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

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.

(1) Represents price per MWh.

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

(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, 2026 and 2025:

(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.

(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, 2026 and December 31, 2025, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

(1) As of June 30, 2026, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.15 billion and $2.2 billion, respectively.

Nuclear Decommissioning Trust Investments

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

(1) Represents amounts before deducting $904 million and $881 million as of June 30, 2026 and December 31, 2025, respectively, primarily related to deferred taxes on appreciation of investment value.

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

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

Customer Credit Trust

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

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

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

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 record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages, and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. 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, 2026.

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 the Utility’s proceeding for review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire under AB 1054 or a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC 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 or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of July 15, 2026, PG&E Corporation and the Utility are aware of approximately 190 complaints on behalf of at least 9,062 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A substantial majority of these claims have been resolved. The court has scheduled and vacated numerous trial dates, including the previously scheduled bellwether trial date of June 23, 2025 and the previously scheduled individual trial date of December 2, 2026. No trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On February 13, 2026, the Court of Appeal denied the writ without opinion. The Utility filed a petition for review with the California Supreme Court, and on April 22, 2026, the California Supreme Court granted the petition for review and transferred the matter back to the Court of Appeal, with directions to vacate its order denying mandate and to issue an order to show cause why the relief sought in the petition should not be granted. The Utility and Cal Fire both filed supplemental briefings with the First District Court of Appeal. In the second quarter of 2026, the Utility and Cal Fire reached a settlement in principle.

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

PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, which the court denied on July 20, 2026.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $2.15 billion as of December 31, 2025 (before available recoveries). During the second quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $100 million for an aggregate liability of $2.25 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.25 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.

The Utility has liability insurance coverage for third-party liability attributable to the 2021 Dixie fire in an aggregate amount of $521 million, substantially all of which was collected as of June 30, 2026.

The Utility recorded an aggregate Wildfire Fund receivable of $1.25 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $1.01 billion as of June 30, 2026. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of June 30, 2026, the Utility also recorded a $97 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $541 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 and the United States Department of Justice. 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 15, 2026, PG&E Corporation and the Utility are aware of approximately 28 complaints on behalf of at least 2,828 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and the Regents of the University of California have each filed a complaint. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into a settlement agreement with five public entities, and their complaint was dismissed on February 4, 2026. In April 2026, PG&E Corporation and the Utility entered into a settlement agreement with PCWA and Middle Fork Project Finance Authority. The court vacated the previously scheduled individual claimant bellwether trial date for April 13, 2026. The next bellwether trial date is set for November 30, 2026.

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

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

On July 10, 2026, the Safety and Enforcement Division of the CPUC (“SED”) published for public comment a proposed administrative consent order and agreement (the “Mosquito SED Settlement”). The Mosquito SED Settlement provides for the Utility to pay $22 million and would resolve the SED’s investigation into the 2022 Mosquito Fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including 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 $350 million as of December 31, 2025 (before available recoveries). During the first quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $50 million for an aggregate liability of $400 million (before available recoveries). The aggregate liability remained unchanged as of June 30, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.

As of June 30, 2026, the Utility recorded an insurance receivable of $418 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees, of which $258 million had been received. As of June 30, 2026, 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 “2021 Dixie Fire” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of June 30, 2026 are:

(1) Includes legal costs of $154 million and $78 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of June 30, 2026.

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, 2026, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $418 million in connection with the 2022 Mosquito fire. 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 2022 Mosquito fire since December 31, 2025:

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire.

FERC TO Rates

The Utility recognizes income subject to potential refunds 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 FERC transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on an order from the FERC approving an all-party settlement in the TO21 rate case, as of June 30, 2026, the Utility recorded reductions of $97 million and $6 million regarding the 2021 Dixie fire and the 2022 Mosquito fire, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of June 30, 2026, 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 $541 million and $54 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate arising from wildfires in any coverage year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of June 30, 2026 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $5.1 billion for 2026. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2026 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On March 2, 2026, the OEIS approved the Utility’s 2025 application and issued the Utility’s 2025 safety certification.

The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

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

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

As of June 30, 2026, PG&E Corporation and the Utility recorded $244 million in Accounts receivable - Other for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:

As of June 30, 2026, the Utility had received $128 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

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, the complexity of the litigation, and the terms of the class 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. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed the Public Employee Retirement Association of New Mexico (“PERA”) as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. On February 26, 2026, the District Court entered an order preliminarily approving the settlement and scheduled the settlement approval hearing for August 25, 2026. On July 6, 2026, the deadline for putative class members to object to the proposed settlement passed with no objections filed.

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. In April 2026, PG&E Corporation and the Utility settled with this group of shareholders. On April 22, 2026, the shareholders filed a request for dismissal pursuant to that settlement agreement, and the District Court terminated the case.

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, such claims could result in (a) the issuance of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of cash with respect to allowed Subordinated Debt Claims.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims, including prosecuting omnibus objections with respect to certain of the Subordinated Claims as necessary.

Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions.

PG&E Corporation and the Utility additionally may have indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors, and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

NOTE 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.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

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

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

The Utility has recovered $516 million in interim rates, which the CPUC approved in a decision on March 7, 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 $516 million in interim rate relief being subject to refund.

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. In 2024, PG&E Corporation decreased its Income tax benefit by $70 million after the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Estimated liabilities for contingencies related to such matters totaled $133 million and $78 million as of June 30, 2026 and 2025, 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.

Environmental Remediation Contingencies

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

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

(2) Primarily driven by Geothermal Landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the 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’s environmental remediation liability as of June 30, 2026, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. As of June 30, 2026, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

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

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

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

(3) Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed.

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

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

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL 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.

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 $44 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 2025 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, 2025, 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 2025 Form 10-K.

Item 2.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This is a combined 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 2025 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 2025 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; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances or changes in interest rates.

The discussions related to the results of operations and liquidity for the three and six months ended June 30, 2025 compared to the same periods in 2024 are 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 Form 10-Q for the three and six months ended June 30, 2025, which was filed with the SEC in July 2025.

Key Factors Affecting Financial Results

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

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

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

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

The financial impact of past wildfires has been significant. In addition to significant liabilities incurred for past wildfires, PG&E Corporation and the Utility have and will continue to incur substantial expenditures in connection with these initiatives. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 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 or Continuation Account coverage year (“Coverage Year”), the Wildfire Fund or the Continuation Account, as applicable, may be available to reimburse the Utility such excess amount. The Utility’s ability to recover wildfire costs depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Wildfire Fund or the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable.

With respect to the Wildfire Fund, PG&E Corporation and the Utility expect to re-evaluate the reasonableness of the currently estimated 20-year life and recognize accelerated amortization of the Wildfire Fund asset based on reliable, publicly available information. SCE has disclosed that a liability for the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”) is probable, but a range of losses that may be incurred is not reasonably estimable. In the first quarter of 2026, SCE has also disclosed losses of $1.3 billion and a Wildfire Fund receivable of $295 million based on their recent settlement activity. As of June 30, 2026, PG&E Corporation and the Utility continue to use an estimated 20-year life and recognized accelerated amortization of $78 million.

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

The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The CPUC could interpret the revised prudency standard under AB 1054 or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover some or all of the expenses that it has recorded as receivables. As of June 30, 2026, the Utility has recorded receivables for regulatory recovery of $638 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. The Utility also received $128 million from the Wildfire Fund related to the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”). The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

For more information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 regarding the Wildfire Fund asset, Note 3 regarding expenditures incurred for wildfire mitigation, “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 10 regarding wildfire liabilities, “Loss Recoveries” in Note 10 regarding recoveries, and “Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application” in “Regulatory Matters” below.

• The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Regulatory Matters” below.

There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented or if there is a failure to act on wildfire matters, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition. In particular, California lawmakers are considering potential legislation in the legislative session scheduled to end August 31, 2026 that could impact PG&E Corporation and the Utility. If there is insufficient legislative action on wildfire matters, PG&E Corporation and the Utility could face persistent financial limitations and elevated risk, including challenges obtaining financing on acceptable terms or increased financing needs, which in turn may negatively impact their financial results and customer affordability. Without sufficient legislation, PG&E Corporation and the Utility may consider changes to their financial plan, including capital allocation priorities.

• PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above.

Tax Matters

PG&E Corporation’s ability to use its U.S. federal and California state net operating loss carryforwards and certain other tax attributes may be significantly limited if the ownership of PG&E Corporation’s stock by certain shareholders increases beyond statutory thresholds. To reduce the possibility of such a limitation, PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and PG&E Corporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 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), in excess of certain thresholds based on the amount and relative value of such stock without approval by the Board of Directors of PG&E Corporation. The computation of the applicable threshold is complex and may vary from date to date; the threshold of the combined value of PG&E Corporation common and mandatory convertible preferred stock was approximately 3.92% as of July 15, 2026. For more information about these restrictions that affect the ownership of PG&E Corporation stock, see “Tax Matters” in Part II, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2025 Form 10-K.

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, 2026 and 2025. 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, 2026 and 2025:

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

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, 2026 and 2025. 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.

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $4 million, or 0%, in the three months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to:

• $201 million more in revenues to recover the cost of electricity in the three months ended June 30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income.

Partially offset by:

• approximately $180 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the three months ended June 30, 2026, compared to the same period in 2025.

The Utility’s electric and natural gas operating revenues increased by $902 million, or 8%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to:

• approximately $620 million in revenues authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the six months ended June 30, 2026, with no comparable revenues in the same period in 2025. The revenues recognized are incremental to revenues previously recognized for interim rate relief; and
• $363 million more in revenues to recover the cost of electricity in the six months ended June 30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income.

Partially offset by:

• approximately $240 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the six months ended June 30, 2026, compared to the same period in 2025.

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-invest 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 from third parties.

The Cost of electricity increased by $201 million, or 34%, and by $363 million, or 36%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily the result of lower CAISO market sales revenues, lower energy contract sales and higher CAISO transmission costs, partially offset by decreases in natural gas prices and volumes used in Utility owned generation.

Cost of Natural Gas

The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-invest 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.

There was no material change to the Cost of natural gas in the three months ended June 30, 2026, compared to the same period in 2025.

The Cost of natural gas decreased by $22 million, or 4%, in the six months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily the result of lower procurement costs due to lower natural gas prices and volumes, partially offset by an increase in greenhouse gas emission expenses associated with California’s cap-and-invest program.

Operating and Maintenance

The Utility’s Operating and maintenance expenses decreased by $317 million, or 11%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to approximately $180 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended June 30, 2026, compared to the same period in 2025.

The Utility’s Operating and maintenance expenses increased by $149 million, or 3%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to:

• approximately $400 million in costs due to recognition of previously deferred expenses authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the six months ended June 30, 2026, with no comparable costs in the same period in 2025. The expenses are incremental to the expenses previously recognized in the 2023 WMCE application as part of interim rate relief.

Partially offset by:

• approximately $240 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the six months ended June 30, 2026, compared to the same period in 2025.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries decreased by $50 million, or 100%, and $99 million, or 100%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. 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 2026.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense increased by $17 million, or 16%, and $43 million, or 23%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily due to accelerated amortization associated with SCE’s disclosure of a receivable from the Wildfire Fund related to the Eaton Fire, with no comparable costs in the same periods in 2025.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization, and decommissioning expenses decreased by $11 million, or 1%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to the reversal of accrued decommissioning expenses due to the sale of a gas storage facility.

The Utility’s Depreciation, amortization, and decommissioning expenses increased by $58 million, or 3%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to the growth in plant balance from capital additions.

Interest Income

The Utility’s Interest income decreased by $72 million, or 40%, and $70 million, or 24%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These decreases were primarily due to lower interest-bearing account balances.

Interest Expense

The Utility’s Interest expense decreased by $14 million, or 2%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to lower interest on regulatory accounts.

The Utility’s Interest expense increased by $48 million, or 4%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to the issuance of additional long-term debt.

Other Income, Net

The Utility’s Other Income, Net increased by $17 million, or 20%, and $64 million, or 42%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily due to a higher return from the trust assets for the qualified pension plan in the three and six months ended June 30, 2026, compared to the same periods in 2025.

Income Tax Provision

The Utility’s Income tax provision decreased by $100 million, or 256%, and $122 million, or 120%, in the three and six months ended June 30, 2026, compared to the same periods in 2025, primarily due to increased deductions for certain costs attributable to electric generation.

The effective tax rates were (7.8)% and (1.1)%, and 7.9% and 8.1% for the three and six months ended June 30, 2026 and 2025, respectively. The changes in effective tax rates are primarily due to increased deductions for certain costs attributable to electric generation. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2026 and 2025 primarily due to the effect of the increase in federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

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

PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.

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

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, 2026, PG&E Corporation and the Utility had access to approximately $6.5 billion of total liquidity comprised of $256 million of the Utility’s Cash and cash equivalents, $716 million of PG&E Corporation’s (on a standalone basis) Cash and cash equivalents and $5.5 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s unsecured credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s unsecured credit rating remains below investment grade with one of the major credit rating agencies, the Utility generally does not receive unsecured credit from its energy procurement counterparties, and it may be required to increase its collateral postings if its credit rating is downgraded.

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, 2026, PG&E Corporation (on a standalone basis) and the Utility had cash and cash equivalents of $716 million and $256 million, respectively.

Financial Resources

Equity Financings

PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect this plan include liquidity and cash flow needs, capital expenditures, interest rates, credit ratings, PG&E Corporation’s common share price, its earnings, the timing and outcome of legislative and 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 and Credit Facilities

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

For more information, see “Credit Facilities” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

DOE Loan Guarantee Agreement

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

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

Other Financings

Citizens Energy Corporation

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

On May 7, 2026, the CPUC issued a final decision authorizing the Utility to file an advice letter seeking approval for each entitlements lease. The transactions contemplated by the agreement remain subject to further FERC and CPUC approvals.

Dividends

PG&E Corporation has announced guidance entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions made by the applicable Board of Directors may be impacted by results of operations, financial condition, cash requirements, contractual restrictions and other factors.

For information on dividend declarations and payments, see Note 6 to the Condensed Consolidated Financial Statements in Part I, Item 1.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the six months ended June 30, 2026 and 2025.

The Utility’s cash flows were as follows:

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities decreased by $448 million, or 11%, during the six months ended June 30, 2026 as compared to the same period in 2025. This decrease was primarily due to an increase in electric procurement costs driven by lower cash receipts on CAISO-related sales and sales of renewable portfolio standard compliance instruments.

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

• the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;
• the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 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 Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments.

The following table summarizes changes in key components of the Utility’s investing cash flows for the six months ended June 30, 2026, compared to June 30, 2025.

Net cash used in investing activities decreased by $109 million, or 2%, during the six months ended June 30, 2026 as compared to the same period in 2025. The decrease was primarily due to a $755 million decrease in net purchases related to customer credit trust investments. The decrease was partially offset by a $623 million increase in capital expenditures, mainly driven by increased investments related to electric distribution customer connections, undergrounding, and distribution maintenance for wildfire risk mitigation.

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

Financing Activities

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation.

The following table summarizes changes in key components of the Utility’s financing cash flows for the six months ended June 30, 2026, compared to June 30, 2025.

Net cash provided by financing activities increased by $752 million, or 45%, during the six months ended June 30, 2026 as compared to the same period in 2025. The increase was primarily due to:

• $1.9 billion increase in proceeds from issuances of long-term debt, net of repayments; and
• $522 million increase in equity contributions received from PG&E Corporation.

Partially offset by:

• $630 million increase in net repayments under credit facilities;
• $860 million increase in net repayments under term loan; and
• $100 million increase in dividend payments.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing or outcome of the following proceedings.

Key updates to the Utility’s regulatory matters include the following:

• In April 2026, the NRC approved the Utility’s 20-year license renewal for extended operations of DCPP; and
• In May 2026, the Utility requested interim rate recovery in the 2027 GRC.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. While the Utility generally expects such unanticipated 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 review and 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.

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

For more information, see Note 3 of the Notes to the 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.

Statuses of the Utility’s cost recovery proceedings are summarized in the following table:

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2023 WMCE Application

As previously disclosed, on February 5, 2026, the CPUC voted out a final decision in the 2023 WMCE proceeding. On March 16, 2026, the Utility filed an application for rehearing of the final decision with the CPUC.

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. Opening and reply briefs were filed on May 8 and June 3, 2026, respectively.

On June 22, 2026, the CPUC extended the statutory deadline in the proceeding from May 21, 2026 to February 19, 2027.

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 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 February 26, 2026, the CPUC issued a decision extending the statutory deadline in the proceeding from March 31, 2026 to October 30, 2026.

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

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

The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as the Utility continues to resolve claims and draw from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

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

Forward-Looking Rate Cases

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

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

Statuses of the Utility’s forward-looking rate cases are summarized in the following table:

Rate Case Request Status

2027 GRC Revenue requirement of $16.64 billion for 2027 Filed May 2025. A PD is expected by March 2027 and a final decision by May 2027. Requested interim rate recovery May 2026.

Transmission Owner Rate Case for 2024 (TO21) Revenue requirement of $2.6 billion for 2026 Accepted December 2023, except as to CAISO adder. All other issues resolved August 2025. In February 2026, the U.S. Supreme Court denied petition for certiorari.

2027 General Rate Case

On May 7, 2026, the Utility requested interim rate recovery effective January 1, 2027, of 55%, 75%, or 85% of its requested 2027 revenue requirement (approximately $653 million, $891 million, and $1.01 billion, respectively), which has been opposed by some intervenors.

Opening briefs were filed on July 2, 2026, and reply briefs will be filed by July 23, 2026.

For more information regarding the 2027 GRC, see the 2025 Form 10-K.

Transmission Owner Rate Case for 2024

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. On August 5, 2025, the FERC issued a decision approving the settlement that resolved all issues in the proceeding. The decision set a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%. For 2026, the Utility’s annual update includes a revenue requirement of $2.6 billion.

On December 29, 2023, the FERC issued an order denying a 0.5% ROE adder. 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, which the FERC denied on June 12, 2024. On June 18, 2024, the Utility and other California IOUs filed an appeal, which the Ninth Circuit Court of Appeals denied on July 11, 2025. After the Ninth Circuit denied a request from the utilities for en banc review on October 7, 2025, they filed a petition for certiorari with the U.S. Supreme Court. On February 23, 2026, the U.S. Supreme Court denied the petition for certiorari.

Other Regulatory Proceedings

Extension of Diablo Canyon Operations

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On April 2, 2026 the NRC approved the Utility’s 20-year license renewal application for extended operations of DCPP. Continued operation of DCPP beyond October 31, 2029 and October 31, 2030, for Unit 1 and Unit 2, respectively, also requires action by the California Legislature.

SB 884 10-Year Distribution Undergrounding Program

On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and San Diego Gas & Electric Company (“SDGE”) requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing.

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

LEGISLATIVE INITIATIVES

SB 254

On April 7, 2026, the Wildfire Fund administrator issued its study report pursuant to SB 254. The report sets out policy options for California’s Governor and Legislature to consider. For more information regarding SB 254, see the 2025 Form 10-K.

LITIGATION AND OTHER MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and in “Regulatory Matters” above that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this 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 2025 Form 10-K.

RISK MANAGEMENT ACTIVITIES

There have been no material changes to the Utility’s or PG&E Corporation’s risk management activities as previously disclosed in Item 7 of the 2025 Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

There have been no material changes to the Utility’s or PG&E Corporation’s critical accounting estimates as previously disclosed in Item 7 of the 2025 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.

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

See accompanying Notes to the Condensed Consolidated Financial Statements.

See accompanying Notes to the Condensed Consolidated Financial Statements.

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 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 which are, in the opinion of the management, of a normal recurring nature and necessary to a fair statement of the results for the interim periods presented. The information as of December 31, 2025 in the Condensed Consolidated Balance Sheets included in this Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2025 Form 10-K. This Form 10-Q should be read in conjunction with the 2025 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.

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.

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

(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, 2026, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

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

Expected credit losses of $30 million and $119 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, 2026, respectively. For the three and six months ended June 30, 2025, expected credit losses were $141 million and $241 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, 2026, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $123 million and $86 million, respectively. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. The RUBA current balancing account balance decreased from December 31, 2025 to June 30, 2026 primarily due to the annual electric and gas rate true-up, which allows the Utility to recover approximately $278 million in undercollections from residential customers in 2026.

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. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of June 30, 2026, 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 six months ended June 30, 2026 and 2025. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final proceeds were received in 2024, and no further disbursements will be made.

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

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

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, 2026, the Condensed Consolidated Statements of Income reflected $22 million and $31 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 $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, 2026, the amount recorded as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP was immaterial. During the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $16 million and $57 million, respectively, as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The 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, 2026 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2026 and December 31, 2025, the SPV had net accounts receivable of $3.3 billion and $3.2 billion, respectively, and outstanding borrowings of $1.8 billion, 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, 2026 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of June 30, 2026 and December 31, 2025, PG&E Recovery Funding LLC had outstanding borrowings of $3.0 billion and $3.1 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, 2026 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate of $7.5 billion of senior secured recovery bonds. As of June 30, 2026 and December 31, 2025, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.0 billion and $7.1 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.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of June 30, 2026, 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, 2026, it did not consolidate any of them.

Contributions to the Wildfire Fund and the Continuation Account

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

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

The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

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

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable. On February 18, 2026, SCE disclosed in its Annual Report on Form 10-K for the year ended December 31, 2025 that it has entered into settlements with insurance claimants and claimants under its Wildfire Recovery Compensation Program related to the Eaton fire. As of March 31, 2026, SCE had recorded $1.3 billion in losses related to these settlements. SCE also recorded expected recoveries from the Wildfire Fund of $295 million. As a result, PG&E Corporation and the Utility accelerated the amortization of the Wildfire Fund asset during the three and six months ended June 30, 2026 as described below.

As of June 30, 2026, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $379 million in Other noncurrent liabilities, $291 million in Current assets - Wildfire Fund asset, and $3.5 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $126 million and $109 million, respectively. During the six months ended June 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $228 million and $185 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.

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

For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 below.

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, 2026 and 2025 were as follows:

(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.

(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.

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:

(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 self-insurance.

(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 self-insurance.

(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 self-insurance.

(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 self-insurance.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Recently Adopted Accounting Standards

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU became effective for PG&E Corporation and the Utility on January 1, 2026. The adoption of this ASU did not have an immediate impact and is not expected to have a significant impact in future periods on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures.

Accounting Standards Issued But Not Yet Adopted

Disaggregation of Income Statement Expenses

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

Intangibles – Goodwill and Other – Internal Use Software

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

Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818), which establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their financial statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Noncurrent regulatory assets are comprised of the following:

Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:

Regulatory Balancing Accounts

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

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

NOTE 4: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2026:

(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 June 22, 2026, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 20, 2031, (ii) increase the aggregate commitments from $5.4 billion to $6.25 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2026, the Utility and the SPV amended the existing $1.75 billion Receivables Securitization Program to extend the scheduled termination date from June 25, 2027 to June 26, 2028.

PG&E Corporation

On June 22, 2026, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2029, (ii) modify both the interest rate pricing grid and commitment fee pricing grid and (iii) add collateral release terms.

Long-Term Debt Issuances and Redemptions

Utility

On February 20, 2026, the Utility completed the sale of (i) $400 million aggregate principal amount of 6.100% first mortgage bonds due 2029, (ii) $1.0 billion aggregate principal amount of 5.200% first mortgage bonds due 2036 and (iii) $800 million aggregate principal amount of 6.000% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of $600 million aggregate principal amount of 2.95% first mortgage bonds due March 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 3, 2026, the Utility completed the sale of (i) $800 million aggregate principal amount of 5.050% first mortgage bonds due 2031, (ii) $800 million aggregate principal amount of 5.600% first mortgage bonds due 2036 and (iii) $600 million aggregate principal amount of 6.300% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of short-term debt, including borrowings outstanding under its revolving credit facility. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

PG&E Corporation

On February 19, 2026, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056. These notes initially bear interest at the rate of 6.850% per annum, and beginning September 15, 2031 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.225% (but not below 6.850%). PG&E Corporation used the net proceeds for general corporate purposes, including repayment of indebtedness.

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, 2026 and December 31, 2025, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion, with unamortized debt issuance costs of $10 million and $13 million, respectively, included in Long-term debt. For both the three and six months ended June 30, 2026 and 2025, the Condensed Consolidated Statements of Income reflected total interest expense of approximately $23 million and $46 million, respectively.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. As of June 30, 2026, 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 customer credit trust (see Note 9 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the six months ended June 30, 2026 and 2025.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. As of December 31, 2025, the Utility had made all required upfront contributions. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2026, the Utility recorded $82 million and $162 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, 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.

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

(1) Includes $3 million and $44 million of returns on investments in the customer credit trust expected to be credited to customers for each of the six months ended June 30, 2026 and 2025, respectively.

NOTE 6: EQUITY

Dividends

Subject to the dividend restrictions as described in Notes 6 and 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 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.

The following table summarizes the dividends paid or declared by PG&E Corporation and the Utility in 2026:

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

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the Income available for common shareholders, basic, by the weighted average number of common shares outstanding, basic. PG&E Corporation’s diluted EPS is calculated by dividing the income available for common shareholders, diluted, by the weighted average number of common shares outstanding, diluted. 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:

(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.

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.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

(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, 2026, the Utility’s outstanding derivative balances were as follows:

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:

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. One major credit agency continues to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of June 30, 2026, 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, self-insurance assets, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

• Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
• Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
• Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

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

(2) Includes approximately $1 billion and $144 million held in the entities for wildfire and non-wildfire self-insurance, respectively.

(3) Represents amount before deducting $904 million primarily related to deferred taxes on appreciation of investment value.

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

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

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

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, 2026 or 2025.

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.

Self-insurance investments

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

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.

(1) Represents price per MWh.

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

(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, 2026 and 2025:

(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.

(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, 2026 and December 31, 2025, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

(1) As of June 30, 2026, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.15 billion and $2.2 billion, respectively.

Nuclear Decommissioning Trust Investments

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

(1) Represents amounts before deducting $904 million and $881 million as of June 30, 2026 and December 31, 2025, respectively, primarily related to deferred taxes on appreciation of investment value.

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

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

Customer Credit Trust

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

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

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

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 record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages, and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. 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, 2026.

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 the Utility’s proceeding for review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire under AB 1054 or a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC 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 or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of July 15, 2026, PG&E Corporation and the Utility are aware of approximately 190 complaints on behalf of at least 9,062 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A substantial majority of these claims have been resolved. The court has scheduled and vacated numerous trial dates, including the previously scheduled bellwether trial date of June 23, 2025 and the previously scheduled individual trial date of December 2, 2026. No trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On February 13, 2026, the Court of Appeal denied the writ without opinion. The Utility filed a petition for review with the California Supreme Court, and on April 22, 2026, the California Supreme Court granted the petition for review and transferred the matter back to the Court of Appeal, with directions to vacate its order denying mandate and to issue an order to show cause why the relief sought in the petition should not be granted. The Utility and Cal Fire both filed supplemental briefings with the First District Court of Appeal. In the second quarter of 2026, the Utility and Cal Fire reached a settlement in principle.

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

PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, which the court denied on July 20, 2026.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $2.15 billion as of December 31, 2025 (before available recoveries). During the second quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $100 million for an aggregate liability of $2.25 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.25 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.

The Utility has liability insurance coverage for third-party liability attributable to the 2021 Dixie fire in an aggregate amount of $521 million, substantially all of which was collected as of June 30, 2026.

The Utility recorded an aggregate Wildfire Fund receivable of $1.25 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $1.01 billion as of June 30, 2026. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of June 30, 2026, the Utility also recorded a $97 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $541 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 and the United States Department of Justice. 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 15, 2026, PG&E Corporation and the Utility are aware of approximately 28 complaints on behalf of at least 2,828 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and the Regents of the University of California have each filed a complaint. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into a settlement agreement with five public entities, and their complaint was dismissed on February 4, 2026. In April 2026, PG&E Corporation and the Utility entered into a settlement agreement with PCWA and Middle Fork Project Finance Authority. The court vacated the previously scheduled individual claimant bellwether trial date for April 13, 2026. The next bellwether trial date is set for November 30, 2026.

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

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

On July 10, 2026, the Safety and Enforcement Division of the CPUC (“SED”) published for public comment a proposed administrative consent order and agreement (the “Mosquito SED Settlement”). The Mosquito SED Settlement provides for the Utility to pay $22 million and would resolve the SED’s investigation into the 2022 Mosquito Fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including 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 $350 million as of December 31, 2025 (before available recoveries). During the first quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $50 million for an aggregate liability of $400 million (before available recoveries). The aggregate liability remained unchanged as of June 30, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.

As of June 30, 2026, the Utility recorded an insurance receivable of $418 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees, of which $258 million had been received. As of June 30, 2026, 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 “2021 Dixie Fire” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of June 30, 2026 are:

(1) Includes legal costs of $154 million and $78 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of June 30, 2026.

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, 2026, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $418 million in connection with the 2022 Mosquito fire. 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 2022 Mosquito fire since December 31, 2025:

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire.

FERC TO Rates

The Utility recognizes income subject to potential refunds 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 FERC transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on an order from the FERC approving an all-party settlement in the TO21 rate case, as of June 30, 2026, the Utility recorded reductions of $97 million and $6 million regarding the 2021 Dixie fire and the 2022 Mosquito fire, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of June 30, 2026, 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 $541 million and $54 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate arising from wildfires in any coverage year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of June 30, 2026 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $5.1 billion for 2026. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2026 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On March 2, 2026, the OEIS approved the Utility’s 2025 application and issued the Utility’s 2025 safety certification.

The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

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

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

As of June 30, 2026, PG&E Corporation and the Utility recorded $244 million in Accounts receivable - Other for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:

As of June 30, 2026, the Utility had received $128 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

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, the complexity of the litigation, and the terms of the class 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. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed the Public Employee Retirement Association of New Mexico (“PERA”) as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. On February 26, 2026, the District Court entered an order preliminarily approving the settlement and scheduled the settlement approval hearing for August 25, 2026. On July 6, 2026, the deadline for putative class members to object to the proposed settlement passed with no objections filed.

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. In April 2026, PG&E Corporation and the Utility settled with this group of shareholders. On April 22, 2026, the shareholders filed a request for dismissal pursuant to that settlement agreement, and the District Court terminated the case.

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, such claims could result in (a) the issuance of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of cash with respect to allowed Subordinated Debt Claims.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims, including prosecuting omnibus objections with respect to certain of the Subordinated Claims as necessary.

Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions.

PG&E Corporation and the Utility additionally may have indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors, and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

NOTE 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.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

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

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

The Utility has recovered $516 million in interim rates, which the CPUC approved in a decision on March 7, 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 $516 million in interim rate relief being subject to refund.

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. In 2024, PG&E Corporation decreased its Income tax benefit by $70 million after the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Estimated liabilities for contingencies related to such matters totaled $133 million and $78 million as of June 30, 2026 and 2025, 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.

Environmental Remediation Contingencies

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

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

(2) Primarily driven by Geothermal Landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the 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’s environmental remediation liability as of June 30, 2026, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. As of June 30, 2026, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

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

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

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

(3) Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed.

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

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

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL 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.

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 $44 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 2025 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, 2025, 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 2025 Form 10-K.