PCG 10-K & 10-Q changes, risk factors and insider trading

The Wildfire FundFund, Continuation Account, and other provisions of AB 1054 and SB 254 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.

If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the disallowance cap under AB 1054 disallowanceand cap.SB 254. Under AB 1054,1054 and SB 254, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on WildfireContinuation FundAccount reimbursement and all aspects of the reformed prudent manager standard. The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited. In addition, if the Utility fails to maintain a valid safety certification at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility. The Utility will be required to reimburse amounts that are determined by the CPUC not to be just and reasonable. For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Furthermore, for the WildfireContinuation FundAccount will onlyto be available for payment of eligible claimsclaims, sothe longWildfire asFund administrator must determine that the Continuation Account is necessary, the CPUC must authorize extending the non-bypassable charge, and there aremust be sufficient funds remaining in the WildfireContinuation Fund.Account. SuchFunds fundsin couldthe Continuation Account may be depleted more quickly than PG&E Corporation’sCorporation and the Utility’sUtility 20-year estimate for the life of the Wildfire Fund (see Note 2 of the Notes to the Consolidated Financial Statements in Item 8), includinganticipate as a result of claims made by California’s other participating electric utility companies. ForPG&E example,Corporation victimsand the Utility are also unable to predict whether the administrator will determine that additional contributions are needed, and if so, the timing of wildfiresthose incontingent Southern California in January 2025 have filed lawsuits alleging that Southern California Edison’s equipment was associated with the ignition of such fires.contributions.

If the Utility is unable to maintain a safety certification or if the WildfireContinuation FundAccount is exhausted,exhausted as a result of claims made by California’s other participating electric utility companies or otherwise, the ineffectivenessunavailability or insufficiency of the WildfireContinuation FundAccount could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Also, the Utility will not be able to obtain any recovery from the WildfireContinuation FundAccount for wildfire-related losses in any year that such losses do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054.

In addition, there could be a significant delay between the occurrence of a wildfire and when the Utility recognizes impairmentaccelerated foramortization of the reductionWildfire inFund future coverageasset due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility. Participation in the Wildfire Fund and the Continuation Account has had, and is expected to havecontinue to have, a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund and the Continuation Account may not ultimately outweigh the substantial costs of the Utility’s contributions to the Wildfire Fund.Fund or the Continuation Account. See “Key Factors Affecting Financial Results” and “Critical Accounting Estimates” in Item 7. MD&A.

PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2021 Dixie fire, or the 2022 Mosquito firefire, or the Wildfire-Related Securities Claims could exceed their accruals,estimated liabilities, or they could be liable as a result of future wildfires.

Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire. PG&E Corporation’s and the Utility’s recorded liabilitiesliability estimates for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. TheSimilarly, PG&E Corporation’s and the Utility’s costs to resolve the Wildfire-Related Securities Claims could exceed their estimated liabilities. PG&E Corporation and the Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. A hearing on the status of restitution in the Butte County District Attorney’s Office’s investigation into the 2018 Camp fire has been continued several times, most recently to April 24, 2026. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in the 2024 Form 10-K.

Additionally, under the doctrine of inverse condemnation, courts have imposed liability against utilities on the grounds that losses borne by the person whose property was damaged through a public-use undertaking should be spread across the community that benefited from such undertaking, even if the utility is unable to recover these costs through rates. In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company (“SDGE”) stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility’s service area. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines. The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in litigation against PG&E Corporation or the Utility.

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

In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the annual safety certification. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires. For more information about the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, and the Wildfire-Related Securities Claims, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation’s and the Utility’s accrued losses for the 2019 Kincade fire and the 2021 Dixie fire of $1.225$1.325 billion and $1.925$2.15 billion exceed the amounts of available liability insurance coverage of $430 million and $527$521 million, respectively. PG&E Corporation and the Utility could also incur substantial costs in excess of insurance coverage in connection with the 2022 Mosquito fire. As of December 31, 2024,2025, the Utility has recorded probable recoveries of $602$632 million and $60$61 million for the 2021 Dixie fire and 2022 Mosquito fire, respectively, through FERC TO rates or as costs recorded to the WEMA. The Utility would not be allowed to recover these costs in excess of insurance to the extent that the CPUC or the FERC determines that they were incurred imprudently. The inability to recover all or a significant portion of costs in excess of insurance through rates could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. For more information on wildfire recovery risk, see “The Wildfire FundFund, Continuation Account, and other provisions of AB 1054 and SB 254 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility’s infrastructure is aging and poses risks to safety and system reliability. The Utility’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. The CPUC will assess penalties on the Utility if there is a finding that the Utility has failed to substantially comply with its WMPs.

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

In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening (such as undergrounding). The Utility’s wildfire mitigation efforts have also benefited in recent years from improved ignition response andhardening, situational awareness tools like weather stationstools, and riskignition modeling.response. These initiatives havereduce significantlybut reduceddo thenot number of CPUC-reportable ignitions and the number of acres burned from utility-related ignitions. The success ofeliminate the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.risk.

Despite these extensive measures, the potential that the Utility’s equipment willmay still be involved in the ignition of future wildfires, including catastrophic wildfires, is significant.wildfires. This risk may be attributable to, andis exacerbated by,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), infrastructure,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 determined by environmental conditions (including weather and vegetation conditions),conditions, third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of December 31, 2024,2025, PG&E Corporation and the Utility hadhave recordedincurred aggregatesignificant liabilities for past wildfires (aggregate liability estimates of $1.225$1.325 billion, $1.925 billion, and $100 millionbillion for claims in connection with the 2019 Kincade fire, $2.15 billion for the 2021 Dixie fire, and the$350 2022million Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire andfor the 2022 Mosquito fire, other probable cost recoveries.fire). These liabilityestimates amountsdo correspondnot toinclude theall lower endcategories of thepotential rangedamages of reasonably estimable probableand losses.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8.

The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover allsome or a portionall of the expenses that it has recorded as receivables. As of December 31, 2024,2025, the Utility has recorded receivables for regulatory recovery of $602$632 million for the 2021 Dixie fire and $60$61 million for the 2022 Mosquito fire. See “2021 Dixie Fire,Fire” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8 for more information.

•The Timing and Outcome of Ratemaking andProceedings, Other Proceedings.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). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded ingreater memorandum and balancing accountsaccount hasbalances increased.increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8, and “Regulatory Matters” below.

•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 plansintends to achieve such savings by improving the planning and execution of its workbusiness through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to minimizereduce financing costs by identifying and executing on opportunities to efficiently finance the business, which dependsdepend 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.1A: “Risk Factors” and “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.above.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations.limitations (which could limit PG&E Corporation’s or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate value of stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and for PG&E Corporation, as amended by theCorporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Accordingly, although PG&E Corporation had 2,671,320,389 common shares outstanding as of February 5, 2025, only 2,193,576,799 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date. For example, based on the closing prices of PG&E Corporation’s common stock and preferred stock as of February 5, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 5, 2025 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation.

The table below shows the Utility’s Consolidated Statements of Income for 20242025 and 2023.2024. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact Net income. The line items with significant net changes are described below.

The Utility’s electric and natural gas operating revenues decreasedincreased by $9$516 million, or 0%,2%, in 20242025 compared to 2023.2024. TheseThe decreasesincrease werewas primarily due to:

•approximately $585$650 million in revenues authorizedto recover the costs associated with extended operations at DCPP in the 2020 WMCE proceeding in 20232025, with no similarcomparable amount in 2024;

•approximately $170$500 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2025, as compared to 2024 with no similar amount in 2023; and

•approximately $85$430 million relatedin torevenues authorized in the 2021 NDCTPWMCE finalproceeding decision(see that“2021 orderedWMCE Application” in the Utility2024 toForm issue a refund of the Non-Qualified Trust to customers10-K) in 20232024, with no comparable refundamount in 2024.2025;

The Utility’s costCost of electricity represents the cost of power and fuel used in the Utility’s generating facilities and purchased from third parties to serve customers. Cost of electricity includes fuel supplied to other third-party generating facilities, costs to comply with California’s cap-and-trade program, realized gains and losses on price risk management activities (see Note 10 of the Notes to the Consolidated Financial Statements in Item 8), and net power purchases from and sales to the CAISO electricity markets and directly from third parties. The costCost of electricity decreasedincreased by $182$348 million in 20242025 as compared to 2023.2024. TheseThis decreasesincrease werewas primarily the result of lowerhigher naturalprocurement gascosts, marketincluding priceslocal includedRA ascontract fuelscosts, costsFERC forapproved applicabletransmission Utilityowner orrate third-partycase generatingsettlement facilities,costs, and higher nuclear fuel amortization, partially offset by lower netincreased CAISO market net sales, increased sales revenues.of various RPS resources, and lower net costs associated with fuel for utility owned generation and contracted generation.

The Utility’s costCost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. The costCost of natural gas decreased by $562$85 million in 20242025 as compared to 2023.2024. TheseThis decreasesdecrease werewas primarily the result of lower naturalGHG gasemission procurement costs, partially offset by lessvolumes, favorable price risk management results,activity bothresulting offrom which were due to lowerreduced natural gas market volatility, and a reduction in contracted transport capacity, partially offset by higher natural gas procurement costs attributed to increased prices forand thedemand, period.along with additional contracted storage capacity.

The Utility’s operatingOperating and maintenance expensesexpense decreased by $126$450 million, or 1%,4%, in 20242025 compared to 2023.2024. TheseThe decreasesdecrease werewas primarily due to:

•a decrease of approximately $160$560 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” belowin the 2024 Form 10-K) in 20232024, with no comparable costs in 2025; and

•approximately $170$540 million of previously deferred expenses authorized in the 2022 WMCE proceeding as part of interim rate relief authorized in the 2023 WMCE application (see “20232022 WMCE Application” below) in 20242024, with no similarcomparable amountcosts in 20232025;

The discussions related to the results of operations and liquidity for the three and six months ended MarchJune 31,30, 2025 compared to the same periodperiods 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 MarchJune 31,30, 2025, which was filed with the SEC in AprilJuly 2025.

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. For more information on incurred expenditures, see Note 3 of the Notes to the Condensed Consolidated Financial Statements. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

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 $1.1$1.3 billion and a Wildfire Fund receivable of $134$295 million based on their recent settlement activity. As of MarchJune 31,30, 2026, PG&E Corporation and the Utility continue to use an estimated 20-year life and recognized accelerated amortization of $27$78 million (see Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1).million.

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 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover some or all of the expenses that it has recorded as receivables. As of MarchJune 31,30, 2026, the Utility has recorded receivables for regulatory recovery of $636$638 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. SeeThe “2021Utility Dixiealso Fire”received and$128 “2022million Mosquito Fire” in Note 10 offrom the NotesWildfire 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 FinancialBalance Statements in Part I, Item 1 for more information.Sheets.

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 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 AprilJuly 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.

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and six months ended MarchJune 31,30, 2026 and 2025. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

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 MarchJune 31,30, 2026 and 2025:

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended MarchJune 31,30, 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.

The Utility’s electric and natural gas operating revenues increased by $898$4 million, or 15%,0%, in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025. This increase was primarily due to:

•approximately $162$201 million more in revenues to recover the cost of electricity in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income; andincome.

•approximately $70$180 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025.

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-tradecap-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 $162$201 million, or 41%,34%, and by $363 million, or 36%, in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025. ThisThese increaseincreases waswere primarily the result of lower CAISO market sales revenues, lower renewable energy creditcontract sales,sales and higher CAISO transmission costs, partially offset by decreases in natural gas prices and volumes used in Utility owned generation.

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-tradecap-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.

TheThere was no material change to the Cost of natural gas decreased by $26 million, or 5%, in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025. This decrease was primarily the result of a decrease in natural gas prices and volumes.

•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 $70$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 MarchJune 31,30, 2026, compared to the same period in 2025.

The Utility’s Wildfire-related claims, net of recoveries decreased by $49$50 million, or 100%, and $99 million, or 100%, in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods 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 MarchJune 31,30, 2025, respectively, with no comparable costs in the same periodperiods in 2026.

The Utility’s Wildfire Fund expense increased by $26$17 million, or 34%,16%, and $43 million, or 23%, in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025. ThisThese increaseincreases waswere primarily due to accelerated amortization associated with SCE’s disclosure of a receivable from the Wildfire Fund related to the Eaton Fire.Fire, with no comparable costs in the same periods in 2025.

The Utility's Depreciation, amortization, and decommissioning expenses increaseddecreased by $69$11 million, or 6%,1%, in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025. This increasedecrease was primarily due to the growthreversal inof plantaccrued balancedecommissioning fromexpenses capitaldue additions andto the recognitionsale of previouslya deferredgas depreciationstorage expense authorized in the 2023 WMCE final decision.facility.

The Utility’s Interest expense increaseddecreased by $62$14 million, or 9%,2%, in the three months ended MarchJune 31,30, 2026, compared to the same period in 2025. This increasedecrease was primarily due to thelower issuanceinterest ofon additionalregulatory long-term debt.accounts.

The Utility’s Other Income, Net increased by $47$17 million, or 66%,20%, and $64 million, or 42%, in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025. ThisThese increaseincreases waswere primarily due to a higher return from the trust assets for the qualified pension plan in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025.

The Utility’s Income tax provision decreased by $22$100 million, or 35%,256%, and $122 million, or 120%, in the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025, primarily due to increased tax repairs deductions and deductions for certain costs attributable to electric generation.

The effective tax rates were 4.1%(7.8)% and 8.3%(1.1)%, and 7.9% and 8.1% for the three and six months ended MarchJune 31,30, 2026 and 2025, respectively. The changechanges in effective tax raterates isare 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.

As of MarchJune 31,30, 2026, PG&E Corporation and the Utility had access to approximately $6.3$6.5 billion of total liquidity comprised of $441$256 million of the Utility’s Cash and cash equivalents, $690$716 million of PG&E Corporation’s (on a standalone basis) Cash and cash equivalents and $5.2$5.5 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

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 MarchJune 31,30, 2026, PG&E Corporation (on a standalone basis) and the Utility had cash and cash equivalents of $690$716 million and $441$256 million, respectively.

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

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 determinedmade by the applicable Board of Directors may be impacted by results of operations, financial condition, cash requirements, contractual restrictions and other factors.

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 threesix months ended MarchJune 31,30, 2026 and 2025.

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 $367$448 million, or 12%,11%, during the threesix months ended MarchJune 31,30, 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.

The following table summarizes changes in key components of the Utility’s investing cash flows for the threesix months ended MarchJune 31,30, 2026, compared to MarchJune 31,30, 2025.

Net cash used in investing activities increaseddecreased by $38$109 million, or 1%,2%, during the threesix months ended MarchJune 31,30, 2026 as compared to the same period in 2025. The increasedecrease was primarily due to a $721$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 transmission and distribution capacity,customer connections, undergrounding, and distribution maintenance for wildfire risk mitigation. The increase was partially offset by a $686 million decrease in net purchases related to customer credit trust investments.

The following table summarizes changes in key components of the Utility’s financing cash flows for the threesix months ended MarchJune 31,30, 2026, compared to MarchJune 31,30, 2025.