ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. Generally, PG&E Corporation’s and the Utility’s revenues vary based on the outcomes of ratemaking proceedings and the amount of pass-through costs incurred. See “Ratemaking Mechanisms” in Item 1. Description of the Business regarding how the Utility’s revenues are determined. Factors that cause costs to vary include the cost of purchased power and fuel; the costs of procurement storage, transportation of natural gas; weather; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances. The discussion related to the results of operations and liquidity for 2024 compared to 2023 is incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC in February 2025. Key Factors Affecting Financial Results PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors: • The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, self-insurance, the Wildfire Fund, the Continuation Account, and regulatory recovery. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, system hardening, situational awareness tools, and ignition response. These initiatives reduce but do not eliminate the Utility’s wildfire risk. 51 Despite these extensive measures, the Utility’s equipment may still be involved in the ignition of future wildfires, including catastrophic wildfires. This risk is exacerbated by a variety of factors, including climate change and severe weather events (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), as well as infrastructure and vegetation conditions. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is determined primarily by environmental and vegetation conditions, third-party suppression efforts, and the location of the wildfire. PG&E Corporation and the Utility have and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts. The financial impact of past wildfires is significant. As of December 31, 2025, PG&E Corporation and the Utility have incurred significant liabilities for past wildfires (aggregate liability estimates of $1.325 billion for the 2019 Kincade fire, $2.15 billion for the 2021 Dixie fire, and $350 million for the 2022 Mosquito fire). These estimates do not include all categories of potential damages and losses. PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8. If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund or Continuation Account coverage year (“Coverage Year”), the Wildfire Fund or the Continuation Account, as applicable, may be available to reimburse the Utility such excess amount. The Utility’s ability to recover wildfire costs depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Wildfire Fund or the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable. With respect to the Wildfire Fund, SCE has disclosed that a liability for the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”) is probable but not reasonably estimable. PG&E Corporation and the Utility expect to reduce their 20-year estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization based on reliable, publicly available information, including when and if SCE accrues a liability or a Wildfire Fund receivable, respectively (see Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8). Recoveries for the 2019 Kincade fire are also subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. The Utility has recorded an aggregate Wildfire Fund receivable of $1.150 billion for the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025. With respect to the Continuation Account, additional uncertainties include whether the Wildfire Fund administrator determines that the Continuation Account is necessary, whether the CPUC authorizes extending the non-bypassable charge, whether the administrator determines that additional contributions are needed and, if so, the timing of those contingent contributions. The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover some or all of the expenses that it has recorded as receivables. As of December 31, 2025, the Utility has recorded receivables for regulatory recovery of $632 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. See “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8 for more information. 52 • The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8, and “Regulatory Matters” below. • There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition. • PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results. For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above. Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $38.3 billion and a California net operating loss carryforward of approximately $34.1 billion as of December 31, 2025. Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation’s or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate value of stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and PG&E Corporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. 53 Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Accordingly, although PG&E Corporation had 2,675,711,544 common shares outstanding as of February 4, 2026, only 2,197,967,954 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date. For example, based on the closing prices of PG&E Corporation’s common stock and preferred stock as of February 4, 2026, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2026 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC. RESULTS OF OPERATIONS The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2025 and 2024.  See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations. PG&E Corporation The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of income (loss) attributable to common shareholders: (in millions) 2025 2024 Net Change Percentage Change Consolidated Total $ 2,593  $ 2,475  $ 118  5  % PG&E Corporation (472) (223) (249) 112  % Utility 3,065  2,698  367  14  % PG&E Corporation’s net loss primarily consists of interest expense on long-term debt. 54 Utility The table below shows the Utility’s Consolidated Statements of Income for 2025 and 2024.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact Net income. The line items with significant net changes are described below. Year Ended December 31, Net Change (1) Percentage Change (in millions) 2025 2024 Electric operating revenues $ 18,318  $ 17,811  $ 507  3  % Natural gas operating revenues 6,617  6,608  9  —  % Total operating revenues 24,935   24,419   516   2   % Cost of electricity 2,609  2,261  348  15  % Cost of natural gas 1,107  1,192  (85) (7) % Operating and maintenance 11,337  11,787  (450) (4) % SB 901 securitization charges, net 35  33  2  6  % Wildfire-related claims, net of recoveries 100  94  6  6  % Wildfire Fund expense 352  383  (31) (8) % Depreciation, amortization, and decommissioning 4,634  4,189  445  11  % Total operating expenses 20,174   19,939   235   1   % Operating income 4,761   4,480   281   6   % Interest income 509  589  (80) (14) % Interest expense (2,713) (2,781) 68  (2) % Other income, net 328  319  9  3  % Income before income taxes 2,885   2,607   278   11   % Income tax benefit (194) (105) (89) 85  % Net income 3,079   2,712   367   14   % Preferred stock dividend requirement 14  14  —  —  % Income Attributable to Common Stock $ 3,065   $ 2,698   $ 367   14   % Operating Revenues The Utility’s electric and natural gas operating revenues increased by $516 million, or 2%, in 2025 compared to 2024. The increase was primarily due to: • approximately $650 million in revenues to recover the costs associated with extended operations at DCPP in 2025, with no comparable amount in 2024; • approximately $500 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2025, as compared to 2024; • approximately $380 million in revenue recognition authorized in the 2024 Transmission Revenue Requirement Reclassification Memo Account (“TRRRMA”) final decision in 2025, with no comparable amount in 2024; and • $348 million in revenues to recover the cost of electricity procurement in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income, partially offset by: • approximately $540 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in 2024, with no comparable amount 2025; • approximately $430 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K ) in 2024, with no comparable amount in 2025; • approximately $260 million less revenue recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below); 55 • approximately $120 million less in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in 2025, as compared to 2024; and • $85 million less in revenues to recover the cost of natural gas in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income. Cost of Electricity The Utility’s Cost of electricity represents the cost of power and fuel used in the Utility’s generating facilities and purchased from third parties to serve customers. Cost of electricity includes fuel supplied to other third-party generating facilities, costs to comply with California’s cap-and-trade program, realized gains and losses on price risk management activities (see Note 10 of the Notes to the Consolidated Financial Statements in Item 8), and net power purchases from and sales to the CAISO electricity markets and directly from third parties. The Cost of electricity increased by $348 million in 2025 as compared to 2024. This increase was primarily the result of higher procurement costs, including local RA contract costs, FERC approved transmission owner rate case settlement costs, and higher nuclear fuel amortization, partially offset by increased CAISO market net sales, increased sales of various RPS resources, and lower net costs associated with fuel for utility owned generation and contracted generation. Cost of Natural Gas The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. The Cost of natural gas decreased by $85 million in 2025 as compared to 2024. This decrease was primarily the result of lower GHG emission volumes, favorable price risk management activity resulting from reduced natural gas market volatility, and a reduction in contracted transport capacity, partially offset by higher natural gas procurement costs attributed to increased prices and demand, along with additional contracted storage capacity. Operating and Maintenance The Utility’s Operating and maintenance expense decreased by $450 million, or 4%, in 2025 compared to 2024. The decrease was primarily due to: • approximately $560 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K ) in 2024, with no comparable costs in 2025; • approximately $540 million of previously deferred expenses authorized in the 2022 WMCE proceeding as part of interim rate relief (see “2022 WMCE Application” below) in 2024, with no comparable costs in 2025; • approximately $260 million less expense recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below); • approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to reclassify these costs to operating expense in 2024, with no comparable costs 2025; and • approximately $150 million less expense recognized in 2025, as compared to 2024, authorized in the GOSMA petition for modification final decision, partially offset by: • approximately $570 million in costs associated with extended operations at DCPP in 2025, with no comparable costs in 2024; • approximately $500 million more in previously deferred expenses in 2025, as compared to 2024, related to interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below); and 56 • approximately $150 million in previously deferred expenses related to VMBA disallowances in the 2023 WMCE final decision (see “2023 WMCE Application” below) in 2025, with no comparable costs in 2024. Depreciation, Amortization, and Decommissioning The Utility’s Depreciation, amortization, and decommissioning expenses increased by $445 million, or 11%, in 2025 compared to 2024. The increase was primarily due to the growth in plant balance from capital additions and the recognition of deferred depreciation expense. Interest Income The Utility’s Interest income decreased by $80 million, or 14%, in 2025 compared to 2024. The decrease was primarily due to a decrease in interest rates and a decrease in interest bearing account balances in 2025, compared to 2024. Income Tax Benefit The Utility’s Income tax benefit increased by $89 million, or 85%, in 2025 compared to 2024. The increase was primarily due to an increased tax repairs deduction and an additional deduction for certain costs attributable to electric generation. The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 2025 2024 Federal statutory income tax rate 21.0  % 21.0  % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (0.6) % (0.8) % Effect of regulatory treatment of fixed asset differences (2) (27.4) % (25.2) % Nontaxable or nondeductible items 1.1  % 0.4  % Tax credits (0.9) % (0.9) % Changes in unrecognized tax benefits 0.1  % 1.9  % Other, net —  % (0.4) % Effective tax rate (6.7) % (4.0) % (1)  Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. LIQUIDITY AND FINANCIAL RESOURCES Overview PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term. PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. 57 PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets. Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2031. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026. As a result, PG&E Corporation expects to pay state income taxes in 2026. See “Tax Matters” above for a discussion of events that could limit PG&E Corporation’s ability to use its net operating losses. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8. As of December 31, 2025, PG&E Corporation and the Utility had access to approximately $4.5 billion of total liquidity comprised of $353 million of the Utility’s Cash and cash equivalents, $360 million of PG&E Corporation’s Cash and cash equivalents, and $3.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. Credit Ratings Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s unsecured credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s unsecured credit rating remains below investment grade with one of the major credit rating agencies, the Utility generally does not receive unsecured credit from its energy procurement counterparties, and it may be required to increase its collateral postings if its credit rating is downgraded. Restrictive Debt Covenants PG&E Corporation’s and the Utility’s credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants. One financial covenant requires that the ratio of total consolidated debt to total consolidated capitalization as of the end of each fiscal quarter be no more than 70% for PG&E Corporation and 65% for the Utility. The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. PG&E Corporation’s and the Utility’s various credit agreements and the DOE Loan Guarantee Agreement contain provisions that may result in an event of default if there was a failure to meet payment terms or observe other covenants under other financing arrangements that could result in an acceleration of payments due. Such provisions are referred to as “cross-default” provisions. As of December 31, 2025, PG&E Corporation and the Utility remain in compliance with all financial covenants. Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of December 31, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $360 million and $353 million, respectively. 58 Financial Resources Equity Financings PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, its share price, its earnings, the timing and outcome of ratemaking proceedings, the timing and terms of other financings, and the outcome of the Wildfire-Related Securities Claims. See “Wildfire-Related Securities Litigation” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8. Debt Financings, Credit Facilities, and Term Loans The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements. For more information, see “Credit Facilities and Term Loans” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8. DOE Loan Guarantee Agreement As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future. For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K. Other Financings Citizens Energy Corporation On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. The transactions contemplated by the agreement are subject to FERC and CPUC approvals. Dividends PG&E Corporation has announced a dividend policy entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions determined by the Board may be impacted by earnings, cash flows, credit metrics, and other business conditions. For information on dividend declarations and payments, see Notes 6 and 7 to the Consolidated Financial Statements in Part II, Item 8. Utility Cash Flows PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the year ended December 31, 2025 and 2024. 59 The Utility’s cash flows were as follows: Year Ended December 31, (in millions) 2025 2024 Net cash provided by operating activities $ 9,035  $ 8,268 Net cash used in investing activities (12,316) (11,375) Net cash provided by financing activities 2,915  3,348 Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents $ (366) $ 241 Operating Activities The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities increased by $767 million, or 9%, in 2025 compared to 2024. This increase was primarily due to: • an increase in collections driven in part by recoveries related to DCPP extended operations; • a decrease in non-wildfire related insurance costs; and • a decrease in wildfire-related payments, net of recoveries. Future cash flow from operating activities will be affected by various factors, including: • the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries; • the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8); • the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information); • the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and • the timing and amount of electric and natural gas commodity price volatility and differences between commodity costs and revenue collections. PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8. Investing Activities The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments. 60 The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2025, compared to December 31, 2024. (in millions) Year Ended December 31, Cash used in investing activities - 2024 $ (11,375) Capital expenditures (1,418) Net purchases related to customer credit trust investments (186) Net purchases related to self-insurance investment and other investing activities 663 Net increase in cash used in investing activities (941) Cash used in investing activities - 2025 $ (12,316) Net cash used in investing activities increased by $0.9 billion, or 8%, in 2025 compared to 2024. This increase was primarily due to a $349 million payment for the purchase of the Oakland General Office, as discussed in Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8, along with higher investments in new business, capacity projects, and distribution system hardening. These increases were partially offset by lower funding related to self‑insurance investments in 2025 compared to 2024. Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will invest $12.4 billion in capital expenditures in 2026. Financing Activities Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation. The following table summarizes changes in key components of the Utility’s financing cash flows for the year ended December 31, 2025, compared to December 31, 2024. (in millions) Year Ended December 31, Cash provided by financing activities - 2024 $ 3,348 Net borrowings under credit facilities 6,574 Net borrowings under term loan 2,675 Repayments of long-term debt, net of proceeds (1,113) AB 1054 recovery bonds issuance (1,409) Short-term debt issuance (1,999) Dividend payments (325) Proceeds from DWR loan (980) Equity contributions from PG&E Corporation (3,785) Other financing activities (71) Net decrease in cash provided by financing activities (433) Cash provided by financing activities - 2025 $ 2,915 Net cash provided by financing activities decreased by $433 million, or 13%, during the year ended December 31, 2025 as compared to the same period in 2024. The decrease was primarily due to: • $3.8 billion decrease in equity contributions received from PG&E Corporation; • $1.1 billion increase in repayments of long-term debt, net of proceeds; • $2.7 billion decrease in net borrowings under term loan; • $1.4 billion of proceeds related to the issuance of senior secured recovery bonds under the AB 1054 securitization in 2024, with no similar transaction in 2025; 61 • $2.0 billion decrease in proceeds related to short-term debt issuance; • $980 million decrease in proceeds related to the DWR loan; and • $325 million increase in dividend payments. Partially offset by: • $6.6 billion increase in net borrowings under credit facilities. REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing or outcome of the following proceedings. Key updates to regulatory matters include the following: • In February 2026, the CPUC issued a final decision in the Utility’s 2023 WMCE proceeding, approving recovery of $1.9 billion of costs. • In February 2026, the OEIS issued a final decision approving the Utility’s 2026–2028 WMP. In December 2025, the Utility submitted its 2025 safety certificate request to OEIS. • In December 2025, the CPUC issued a final decision in the Utility’s 2026 Cost of Capital proceeding that set the Utility’s ROE at 9.98% effective January 1, 2026 and approved a yield spread adjustment. • In December 2025, the CPUC approved a resolution that updated CPUC guidelines for implementation of the SB 884 undergrounding program. • In November 2025, the Utility filed the Kincade and Dixie AB 1054 Wildfire Cost Review and Recovery Proceeding application requesting recovery of approximately $1.59 billion of WEMA costs, review of costs drawn from the Wildfire Fund, and recovery of $314 million of CEMA costs. • In August 2025, the FERC approved an all-party settlement in the Utility’s Transmission Owner Rate Case for 2024 (the “TO21” rate case). • In August 2025, the CPUC issued a final decision that increases the cost cap for 2025 and 2026 by an aggregate $2.38 billion in connection with the Order Instituting Rulemaking (“OIR”) to Establish Energization Timelines. • In September 2025, the CPUC issued a final decision approving $1.06 billion in cost recovery in the 2022 WMCE proceeding. • In May 2025, the Utility filed its 2027 GRC application with the CPUC. Cost Recovery Proceedings Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs. 62 In recent years, the Utility has recorded significant amounts to these accounts. Because rate recovery may require CPUC authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2025, the Utility had recorded an aggregate amount of approximately $2.2 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, and WMBA, substantially all of which was accounted for as long term. See Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8. If the amount of the costs recorded in these accounts increases, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below. Key updates to the Utility’s cost recovery proceedings are summarized in the following table: Proceeding Request (1) Status 2022 WMCE $1.36 billion of cost recovery Final decision authorizing $1.06 billion of total cost recovery issued September 2025. 2023 WMCE $2.18 billion of cost recovery Final decision authorizing $1.9 billion of costs issued February 2026. 2024 WMCE $596 million of cost recovery Application filed November 2024. 2023 WGSC $2.5 billion of cost recovery Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024. Kincade and Dixie AB 1054 Review of 2019 Kincade fire and 2021 Dixie fire costs, including recovery of approximately $1.9 billion Application filed November 2025. (1) The revenue requirement amounts requested do not include interest. Wildfire Mitigation and Catastrophic Events Cost Recovery Applications 2022 WMCE Application On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in the 2022 WMCE application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021. The recorded expenditures consisted of $1.2 billion in expenses and $136 million in capital expenditures. On September 26, 2025, the CPUC issued a final decision adopting the settlement agreement and authorizing total cost recovery for this matter of $1.06 billion. The final decision disallowed $217 million in VMBA costs. 2023 WMCE Application On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 WMCE application”). The costs addressed in the 2023 WMCE application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2022. The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event. 63 On September 16, 2024, the CPUC issued a final decision on interim rate recovery that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. On February 5, 2026, the CPUC voted out a final decision, which approved recovery of $1.9 billion of costs. The final decision denied recovery of $173 million in vegetation management costs. 2024 WMCE Application On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in the 2024 WMCE application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023. The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in the CEMA. Wildfire and Gas Safety Costs Recovery Application On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs. The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization efforts consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table: (in millions) Recorded Costs WMPMA $ 2,095 FRMMA 165 Gas storage balancing account 101 In line inspection memorandum account 92 Other 45 Total $ 2,498 In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. On June 12, 2025, the CPUC issued a decision extending the statutory deadline in the proceeding from June 30, 2025 to March 31, 2026. Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA. 64 The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as the Utility continues to resolve claims and draw from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 14 of the Notes to the Consolidated Financial Statements. The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months. Forward-Looking Rate Cases The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases. Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risks associated with the lower level of work achieved compared to that funded by the CPUC. Key updates to the Utility’s forward-looking rate cases are summarized in the following table: Rate Case Request Status 2027 GRC Revenue requirement of $16.64 billion for 2027 Filed May 2025. A PD is expected by March 2027 and a final decision by May 2027. 2026 Cost of Capital Increase ROE to 11.30% and cost of debt to 5.04% Final decision approving ROE of 9.98% and cost of debt of 5.04% issued December 2025. Transmission Owner Rate Case for 2024 (TO21) Revenue requirement of $2.78 billion for 2024, subject to true-up and refund Accepted December 2023, except as to CAISO adder. All other issues resolved August 2025. 2027 General Rate Case On May 15, 2025, the Utility filed its 2027 GRC application with the CPUC. In the 2027 GRC, the CPUC will determine the annual amount of revenue requirements that the Utility will be authorized to collect through rates from 2027 through 2030 to recover its anticipated costs for gas distribution, transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. On November 10, 2025, the Utility submitted errata to update its GRC opening testimony and revenue requirement request. The table below compares the portion of CPUC jurisdictional revenue requirements and weighted-average rate base that are requested in the GRC proceeding, as updated, from 2027 through 2030 to the amounts adopted for 2026 in the 2023 GRC and other cost recovery proceedings: Year Requested revenue requirement (in billions) Requested weighted-average GRC rate base 2026 (as adopted) $ 15.4  54.0 2027 16.6  67.0 2028 17.6  73.4 2029 18.7  79.4 2030 19.8  85.4 65 In the 2027 GRC application, the Utility proposed various safety, resiliency, and clean energy investments. Among other things, the Utility proposed to invest a total of approximately $45.0 billion between 2027 and 2030 in CPUC-jurisdictional assets. The proposed investments would support wildfire safety (including undergrounding 307 miles of electrical lines in 2027 and 400 miles per year for 2028 through 2030 until a 10-year undergrounding plan is approved), grid modernization, gas system safety, clean energy, and resilience. In addition, the Utility requested authorization to establish new balancing accounts for new business capital spend and employee medical expenses. The Utility is not seeking recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7. On July 31, 2025, the CPUC issued a scoping memo that modifies the standard rate case plan schedule. The scoping memo indicates that the CPUC will issue a PD by March 2027 and a final decision by May 2027. Cost of Capital Proceedings 2026 Cost of Capital Application On March 20, 2025, the Utility (along with the other IOUs in California) submitted its 2026 Cost of Capital application. On December 18, 2025, the CPUC issued a final decision and approved the following cost of capital rates, which went into effect beginning January 1, 2026: Cost Weight Weighted Cost Return on Common Equity 9.98% 52.00% 5.19% Return on Preferred Equity 5.52% 0.50% 0.03% Return on Long-term debt 5.04% 47.50% 2.39% T he decision approved a revenue credit to return the benefit of potential DOE loan draws to customers and a temporary yield spread adjustment to compensate the Utility for its actual cost of short-term debt above the commercial paper rate. The yield spread adjustment for 2026 is 125 basis points. The decision also continued the Cost of Capital mechanism pursuant to which the Utility’s ROE will be adjusted and the cost of debt will be trued up to the most recent recorded cost of debt upon a significant change in rates. Transmission Owner Rate Case for 2024 On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasted a 2024 retail electric transmission revenue requirement of $2.83 billion. The Utility requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO. The TO21 filing also addresses the Utility’s capital structure and several new issues including wildfire self-insurance recovery from transmission customers. On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but denying the 0.5% ROE adder for participation in the CAISO, which results in a forecast transmission revenue requirement of $2.78 billion. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO. On June 12, 2024, the FERC issued an order denying the Utility’s request for rehearing. On June 18, 2024, the Utility and other California IOUs filed an appeal of the FERC’s order denying the Utility’s request for rehearing. On July 11, 2025, the Ninth Circuit Court of Appeals denied the utilities’ joint appeal. On August 20, 2025, the Utility and California IOUs sought en banc review from the Ninth Circuit. On September 15, 2025, the Ninth Circuit denied en banc review. On October 7, 2025, the Utility and California IOUs filed a petition for certiorari with the Supreme Court. On March 21, 2025, the Utility filed with the FERC a settlement in the TO21 rate case. On August 5, 2025, the FERC issued a decision approving the settlement and resolving all contested issues in the proceeding, as well as specific wildfire cost recovery issues raised by stakeholders in prior proceedings related to the Utility’s TO tariff. The decision sets a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%. 66 On December 1, 2025, the Utility filed with the FERC the TO annual update for rate year 2026, which included the provisions of the TO21 settlement. The revenue requirement for rates that went into effect on January 1, 2026 is $2.6 billion, which represents a decrease from the 2025 revenue requirement of $2.9 billion. Other Regulatory Proceedings 2026-2028 Wildfire Mitigation Plan On April 4, 2025, the Utility submitted to the OEIS its 2026-2028 WMP, which it revised on July 28, 2025. The 2026-2028 WMP provides a comprehensive overview of the Utility’s wildfire mitigation strategy and incorporates lessons learned from previous years and emerging best practices. On February 5, 2026, the OEIS issued a final decision approving the Utility’s 2026–2028 WMP. Extension of Diablo Canyon Operations On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at DCPP through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility continues to operate DCPP on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs are responsible for the cost of extended operations. The key steps to continued operations are NRC license renewal and approvals from several California state agencies. As of December 31, 2025, the Utility has received all necessary state approvals except for approval from the Central Coast Region Water Quality Control Board. The CPUC’s approval is subject to the following conditions: (1) the NRC continues to authorize DCPP operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that DCPP extended operations are imprudent or unreasonable. On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On December 19, 2023, the NRC deemed the application sufficient, which allows continued operations at DCPP past the plant’s current licenses until the relicensing review is complete. In June 2025, the NRC issued the final safety evaluation report and supplemental environmental impact statement. SB 884 10-Year Distribution Undergrounding Program On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and SDGE requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing. On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines. LEGISLATIVE AND REGULATORY INITIATIVES SB 254 On September 19, 2025, SB 254 became law and became effective. Among other things, the law provides for the Continuation Account, which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims incurred by large electric corporations (as defined in SB 254), if the Wildfire Fund is depleted. Each of California’s large electric IOUs has elected to participate in the Continuation Account. The Continuation Account would be similar to the Wildfire Fund, except: • The Continuation Account would provide up to $18 billion of liquidity. If the Wildfire Fund administrator determines that the Continuation Account is necessary prior to December 31, 2028, the CPUC will consider whether to extend the non-bypassable charge on customers from 2036 through 2045. If the CPUC extends the non-bypassable charge on customers, the participating utilities’ annual $300 million contributions will be extended from 2029 through 2045. 67 The Wildfire Fund administrator is also authorized to determine if additional annual contributions are needed, in which case the participating utilities will contribute an additional $3.9 billion in equal installment payments over five years. If the administrator winds up and terminates the Continuation Account before the final installment payment is made, the utilities will return one-half of the unpaid installment payments as rate credits to customers. The Utility’s allocation among the participating utilities for these contributions is 47.85%. • If a utility is required to reimburse the Continuation Account, the amount of reimbursement will be reduced by the amount of contributions for which the utility has not claimed a reduction. • The disallowance cap on reimbursements, which is equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base, is determined based on the year of the ignition. This revised disallowance cap applies to fires occurring before or after the effective date of SB 254. Assets in the Continuation Account are separate from the Wildfire Fund and are not available for fires ignited before the effective date of SB 254. For fires that destroy 1,000 or more structures, SB 254 gives the participating utilities a right of first refusal over insurers’ transactions to sell their right of subrogation, reimbursement, or recovery. SB 254 also prohibits the Utility from including in its equity rate base the first $2.9 billion that it first expends on fire risk mitigation capital expenditures approved by the CPUC on or after January 1, 2026. The Utility expects to finance this amount with securitization. SB 254 requires the Wildfire Fund administrator to prepare a report by April 1, 2026 that evaluates and sets forth recommendations on new models or approaches that mitigate damage, accelerate recovery, and responsibly and equitably allocate the burdens from natural catastrophes, including catastrophic wildfires, earthquakes, and other natural disasters, across stakeholders, including insurers, communities, homeowners, landowners, governments, large electrical corporations, and local publicly owned electric utilities, to complement or replace the Wildfire Fund. LITIGATION AND OTHER MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 and in “Regulatory Matters” above that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. ENVIRONMENTAL MATTERS The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See Item 1A: “Risk Factors,” “Environmental Regulation” in Item 1 and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. RISK MANAGEMENT ACTIVITIES PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit. The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. 68 Commodity Price Risk The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism. The Utility does not have a balancing account for costs in excess of its revenue requirement for natural gas transportation and storage service to non-core customers. The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. PG&E Corporation uses value-at-risk to measure its shareholders’ exposure to these risks. The value-at-risk was approximately $4 million and $5 million at December 31, 2025 and 2024, respectively. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities. Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2025 and 2024, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $37 million and $6 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates. Energy Procurement Credit Risk The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, which may be higher than the contract prices. The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility executes many energy contracts under master commodity enabling agreements that may require security. Security may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Security or performance assurance may be required from the Utility or counterparties when current net receivables or payables and exposure exceed contractually specified limits. The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: Exposure  (1) (in millions) Number of Wholesale Customers or Counterparties

10% Net Credit Exposure to Wholesale Customers or Counterparties 10% (in millions) December 31, 2025 $ 1,048  4  $ 714 December 31, 2024 $ 1,114  4  $ 708 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity. 69 CRITICAL ACCOUNTING ESTIMATES The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. Contributions to the Wildfire Fund PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below. AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the longevity of the fund, PG&E Corporation and the Utility use a dataset with historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The simulation began with 12 years of publicly available fire-loss data, and PG&E Corporation and the Utility add an additional year of data each subsequent year. In addition to historical data, significant assumptions also include the estimated amount of Wildfire Fund claim payments, the number of years of fire-loss data, estimated costs of wildfire settlement claims from other participating utilities, CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and the amounts required to be reimbursed to the Wildfire Fund, and the effects of climate change. Due to the significant judgment required to estimate the life of the Wildfire Fund, there is a high degree of uncertainty for many of these assumptions, and so subsequent changes to the available information could materially impact the remaining estimated life of the fund. Based upon the outcome of newly run Monte Carlo simulations when known information becomes available, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. For instance, in 2024, a re-evaluation in the estimate resulted in the Wildfire Fund life increasing from 15 to 20 years. Estimates for the useful life of the Wildfire Fund and the accelerated amortization of the fund, respectively, are based on a variety of assumptions and are subject to uncertainty and change as additional information becomes publicly available. The estimated life of the Wildfire Fund reflects wildfire risk in the state, while accelerated amortization anticipates potential draw-downs of the Wildfire Fund. Both of these estimates have a high degree of uncertainty since they rely on a number of assumptions, such as potential wildfire claim payments, future wildfire activity, regulatory decisions, and any potential disclosed cost of wildfires caused by other participating electric utilities. SCE has disclosed that a liability for the Eaton fire is probable but not reasonably estimable. PG&E Corporation and the Utility expect to reduce their 20-year estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization based on reliable, publicly available information, including when and if SCE accrues a liability or a Wildfire Fund receivable, respectively. As a result, the Wildfire Fund asset could be amortized down to zero in the near future. For every $5 billion of Wildfire Fund receivables recorded by a participating utility, PG&E Corporation and the Utility expect that they would record approximately $1 billion of accelerated amortization. As of December 31, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $377 million in Other noncurrent liabilities, $297 million in Current assets - Wildfire Fund asset, and $3.7 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $352 million and $383 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. 70 The Monte Carlo simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Initial use of five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, would have resulted in a six year amortization period. As of December 31, 2025, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by ten years assuming greater effectiveness and would decrease the amortization period by five years assuming less effectiveness. Other assumptions used to estimate the useful life include the disclosed cost of wildfires caused by participating electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period. For more information, see “Contributions to the Wildfire Fund and the Continuation Account” in Note 2 and “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Loss Contingencies PG&E Corporation and the Utility record an estimated liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. As discussed below, PG&E Corporation and the Utility have recorded material estimated liabilities for various wildfire-related, enforcement, environmental remediation, and other legal matters. For more information about PG&E Corporation’s and the Utility’s accounting policies and sources of uncertainty in these estimates, see Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8. PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The process for estimating liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience. As more information becomes available, including from potential claimants as litigation or resolutions progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. With respect to environmental remediation, as of December 31, 2025 and 2024, the Utility’s estimated undiscounted gross environmental liabilities were $1.2 billion each. The Utility’s undiscounted future costs could increase to as much as $2.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. 71 Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss, and they can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, communications with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations . Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2025, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $22.6 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $24.3 billion. Determining probability requires significant judgment by management and includes consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility’s regulatory assets, including utility-retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. A portion of the Utility’s regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account, and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. Additionally, SB 901 provides a mechanism for the CPUC to allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (“CHT”). SB 901 required the CPUC to establish the CHT to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2025, the SB 901 regulatory asset was approximately $5.1 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered.  The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. 72 Asset Retirement Obligations PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and estimated decommissioning dates. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plant. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. At December 31, 2025, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.4 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. Pension and Other Postretirement Benefit Plans PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP, and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery through rates. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate, and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8. In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2026 was 7.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2036 and beyond. Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of 7.0% compares to a ten-year actual return of 5.7%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 831 Aa-grade non-callable bonds at December 31, 2025. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. 73 The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2025 Pension Costs Increase in Projected Benefit Obligation at December 31, 2025 Discount rate (0.50) % $ 13  $ 1,148 Rate of return on plan assets (0.50) % 82  — Rate of increase in compensation 0.50  % 35  267 The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2025 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2025 Health care cost trend rate 0.50  % $ 6  $ 41 Discount rate (0.50) % 6  89 Rate of return on plan assets (0.50) % 12  — ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED See Note 2 of the Notes to the Consolidated Financial Statements in Item 8. NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Notes to the Consolidated Financial Statements in Item 8. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 74 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PG&E CORPORATION CONSOLIDATED STATEMENTS OF INCOME (in millions, except per share amounts) Year ended December 31, 2025 2024 2023 Operating Revenues Electric $ 18,318   $ 17,811   $ 17,424 Natural gas 6,617   6,608   7,004 Total operating revenues 24,935   24,419   24,428 Operating Expenses Cost of electricity 2,609   2,261   2,443 Cost of natural gas 1,107   1,192   1,754 Operating and maintenance 11,349   11,808   11,924 SB 901 securitization charges, net 35   33   1,267 Wildfire-related claims, net of recoveries 100   94   64 Wildfire Fund expense 352   383   567 Depreciation, amortization, and decommissioning 4,634   4,189   3,738 Total operating expenses 20,186   19,960   21,757 Operating Income 4,749   4,459   2,671 Interest income 520   604   606 Interest expense ( 3,028 ) ( 3,051 ) ( 2,850 ) Other income, net 182   300   272 Income Before Income Taxes 2,423   2,312   699 Income tax benefit ( 280 ) ( 200 ) ( 1,557 ) Net Income 2,703   2,512   2,256 Preferred stock dividend requirement 110   37   14 Income Available for Common Shareholders $ 2,593   $ 2,475   $ 2,242 Weighted Average Common Shares Outstanding, Basic 2,197   2,141   2,064 Weighted Average Common Shares Outstanding, Diluted 2,202   2,147   2,138 Net Income Per Common Share, Basic $ 1.18   $ 1.16   $ 1.09 Net Income Per Common Share, Diluted $ 1.18   $ 1.15   $ 1.05 See accompanying Notes to the Consolidated Financial Statements. 75 PG&E CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions) Year ended December 31, 2025 2024 2023 Net Income $ 2,703   $ 2,512   $ 2,256 Other Comprehensive Income (Loss) Pension and other postretirement benefit plans obligations (net of taxes of $ 4 , $ 3 , and $ 6 , respectively) ( 11 ) ( 7 ) ( 16 ) Net unrealized gain (losses) on available-for-sale securities (net of taxes of $ 2 , $ 0 , and $ 3 , respectively) 5   1   8 Total other comprehensive income (loss) ( 6 ) ( 6 ) ( 8 ) Comprehensive Income 2,697   2,506   2,248 Preferred stock dividend requirement 110   37   14 Comprehensive Income Attributable to Common Shareholders $ 2,587   $ 2,469   $ 2,234 See accompanying Notes to the Consolidated Financial Statements. 76 PG&E CORPORATION CONSOLIDATED BALANCE SHEETS (in millions) Balance at December 31, 2025 December 31, 2024 ASSETS Current Assets Cash and cash equivalents $ 713   $ 940 Restricted cash and restricted cash equivalents (includes $ 225 million and $ 263 million related to VIEs at respective dates) 259   273 Accounts receivable Customers (net of allowance for doubtful accounts of $ 408 million and $ 418 million at respective dates) (includes $ 1.9 billion related to VIEs, net of allowance for doubtful accounts of $ 408 million and $ 418 million at respective dates) 2,267   2,220 Accrued unbilled revenue (includes $ 1.3 billion related to VIEs at respective dates) 1,463   1,487 Regulatory balancing accounts 6,300   7,227 Other (net of allowance for doubtful accounts of $ 69 million and $ 35 million at respective dates) 1,719   1,810 Regulatory assets 305   234 Inventories Gas stored underground and fuel oil 75   52 Materials and supplies 745   768 Wildfire Fund asset 297   301 Wildfire self-insurance asset 1,043   905 Other 644   999 Total current assets 15,830   17,216 Property, Plant, and Equipment Property, Plant, and Equipment 128,989   118,262 Construction work in progress 4,627   4,458 Financing lease ROU asset and other 2   814 Total property, plant, and equipment 133,618   123,534 Accumulated depreciation ( 37,270 ) ( 35,305 ) Net property, plant, and equipment 96,348   88,229 Other Noncurrent Assets Regulatory assets 15,981   15,561 Customer credit trust 804   377 Nuclear decommissioning trusts 4,230   3,833 Operating lease ROU asset 450   524 Wildfire Fund asset 3,728   4,070 Other (includes noncurrent accounts receivable of $ 67  million and $ 82 related to VIEs, net of noncurrent allowance for doubtful accounts of $ 15  million and $ 18 at respective dates) 4,240   3,850 Total other noncurrent assets 29,433   28,215 TOTAL ASSETS $ 141,611   $ 133,660 See accompanying Notes to the Consolidated Financial Statements. 77 PG&E CORPORATION CONSOLIDATED BALANCE SHEETS (in millions, except share amounts) Balance at December 31, 2025 December 31, 2024 LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 2,675   $ 1,523 Long-term debt, classified as current (includes $ 221 million and $ 222 million related to VIEs at respective dates) 821   2,146 Accounts payable Trade creditors 3,353   2,748 Regulatory balancing accounts 3,119   3,169 Other 929   748 Operating lease liabilities 90   85 Financing lease liabilities —   577 Interest payable (includes $ 72 million and $ 91 million related to VIEs at respective dates) 764   760 Wildfire-related claims 524   916 Other 4,025   3,658 Total current liabilities 16,300   16,330 Noncurrent Liabilities Long-term debt (includes $ 11.7 billion and $ 10.1 billion related to VIEs at respective dates) 57,387   53,569 Regulatory liabilities 20,188   19,417 Pension and other postretirement benefits 549   808 Asset retirement obligations 5,439   5,444 Deferred income taxes 4,135   3,082 Operating lease liabilities 360   439 Financing lease liabilities 2   4 Other 4,459   4,166 Total noncurrent liabilities 92,519   86,929 Equity Shareholders’ Equity Mandatory convertible preferred stock 1,579   1,579 Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,197,942,874 and 2,193,573,536 shares outstanding at respective dates 31,636   31,555 Reinvested earnings ( 650 ) ( 2,966 ) Accumulated other comprehensive loss ( 25 ) ( 19 ) Total shareholders’ equity 32,540   30,149 Noncontrolling Interest - Preferred Stock of Subsidiary 252   252 Total equity 32,792   30,401 TOTAL LIABILITIES AND EQUITY $ 141,611   $ 133,660 See accompanying Notes to the Consolidated Financial Statements. 78 PG&E CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2025 2024 2023 Cash Flows from Operating Activities Net income $ 2,703   $ 2,512   $ 2,256 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 4,634   4,189   3,738 Bad debt expense 402   341   636 Allowance for equity funds used during construction ( 219 ) ( 184 ) ( 179 ) Deferred income taxes and tax credits, net 1,058   1,098   ( 765 ) Wildfire Fund expense 352   383   568 Other ( 75 ) 310   ( 116 ) Effect of changes in operating assets and liabilities: Accounts receivable ( 61 ) ( 1,061 ) ( 369 ) Wildfire-related insurance receivable ( 167 ) 318   358 Inventories —   45   ( 28 ) Accounts payable 176   30   ( 90 ) Wildfire-related claims ( 392 ) ( 506 ) ( 489 ) Other current assets and liabilities 563   ( 231 ) 397 Regulatory assets, liabilities, and balancing accounts, net 173   1,545   ( 429 ) Contributions to Wildfire Fund ( 193 ) ( 193 ) ( 193 ) Other noncurrent assets and liabilities ( 238 ) ( 561 ) ( 548 ) Net cash provided by operating activities 8,716   8,035   4,747 Cash Flows from Investing Activities Capital expenditures ( 11,787 ) ( 10,369 ) ( 9,714 ) Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952   1,980   2,235 Purchases of nuclear decommissioning trust investments ( 1,993 ) ( 2,002 ) ( 2,252 ) Proceeds from sales and maturities of customer credit trust investments 435   398   556 Purchases of customer credit trust investments ( 742 ) ( 519 ) — Proceeds from sales and maturities of self-insurance investments 1,181   —   — Purchases of self-insurance investments ( 1,384 ) ( 898 ) — Other 22   35   13 Net cash used in investing activities ( 12,316 ) ( 11,375 ) ( 9,162 ) Cash Flows from Financing Activities Borrowings under credit facilities 4,790   6,873   10,675 Repayments under credit facilities ( 1,465 ) ( 10,122 ) ( 10,540 ) Borrowings under term loan 575   —   2,100 Repayments under term loan —   ( 2,600 ) ( 2,181 ) Short-term debt financing, net of issuance costs of $ 0 , $ 1 , and $ 0 at respective dates —   999   — Short-term debt matured ( 1,000 ) —   — Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $ 38 , $ 5 , and $ 67 at respective dates 4,962   4,495   5,483 Repayment of long-term debt ( 3,876 ) ( 800 ) ( 3,075 ) 79 Proceeds from issuance of AB 1054 recovery bonds, net of financing fees of $ 0 , $ 10 and $ 0 at respective dates —   1,409   — Repayment of AB 1054 recovery bonds ( 88 ) ( 46 ) ( 38 ) Repayment of SB 901 recovery bonds ( 135 ) ( 129 ) ( 130 ) Proceeds from DWR loan —   980   — Proceeds from issuance of convertible notes, net of discount and issuance costs of $ 0 , $ 0 , and $ 27 at respective dates —   —   2,123 Common stock issued —   1,128   — Mandatory convertible preferred stock issued —   1,579   — Common stock dividends paid ( 220 ) ( 86 ) — Mandatory convertible preferred stock dividends paid ( 97 ) —   — Other ( 87 ) ( 59 ) ( 17 ) Net cash provided by financing activities 3,359   3,621   4,400 Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents ( 241 ) 281   ( 15 ) Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 1,213   932   947 Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 $ 972   $ 1,213   $ 932 Less: Restricted cash and restricted cash equivalents ( 259 ) ( 273 ) ( 297 ) Cash and cash equivalents at December 31 $ 713   $ 940   $ 635 Supplemental disclosures of cash flow information Cash paid for: Interest, net of amounts capitalized $ ( 2,665 ) $ ( 2,421 ) $ ( 2,286 ) Supplemental disclosures of noncash investing and financing activities Capital expenditures financed through accounts payable $ 1,859   $ 1,144   $ 1,105 Operating lease liabilities arising from obtaining ROU assets —   6   269 Financing lease liabilities arising from obtaining ROU assets —   43   52 Reclassification of operating lease liabilities to financing lease liabilities —   —   913 DWR loan forgiveness and performance-based disbursements 148   192   214 Changes to PG&E Corporation common stock and treasury stock in connection with share exchanges with the Fire Victim Trust —   —   ( 2,517 ) Common stock dividends declared but not yet paid 111   55   21 Mandatory convertible preferred stock dividends declared but not yet paid 23   23   — Capital expenditures financed through current assets and non-current liabilities 592   —   — See accompanying Notes to the Consolidated Financial Statements. 80 PG&E CORPORATION CONSOLIDATED STATEMENTS OF EQUITY (in millions, except share amounts) Preferred Stock Common Stock Treasury Stock Reinvested Earnings Accumulated Other Comprehensive Income (Loss) Total Shareholders' Equity Non- controlling Interest - Preferred Stock  of Subsidiary Total Equity Shares Amount Shares Amount Balance at December 31, 2022 $ —   1,987,784,948   $ 32,887   247,743,590   $ ( 2,517 ) $ ( 7,542 ) $ ( 5 ) $ 22,823   $ 252   $ 23,075 Net income —  —  —  —  —  2,256   —  2,256   —  2,256 Other comprehensive loss —  —  —  —  —  —  ( 8 ) ( 8 ) —  ( 8 ) Common stock issued, net —  145,812,810   ( 2,517 ) —  —  —  —  ( 2,517 ) —  ( 2,517 ) Treasury stock disposition —  —  —  ( 247,743,590 ) 2,517   —  —  2,517   —  2,517 Stock-based compensation amortization —  —  4   —  —  —  —  4   —  4 Common stock dividends declared —  —  —  —  —  ( 21 ) —  ( 21 ) —  ( 21 ) Preferred stock dividend requirement of subsidiary —  —  —  —  —  ( 14 ) —  ( 14 ) —  ( 14 ) Balance at December 31, 2023 $ —   2,133,597,758   $ 30,374   —   $ —   $ ( 5,321 ) $ ( 13 ) $ 25,040   $ 252   $ 25,292 Net income —  —  —  —  —  2,512   —  2,512   —  2,512 Other comprehensive loss —  —  —  —  —  —  ( 6 ) ( 6 ) —  ( 6 ) Preferred Stock issued, net 1,579   —  —  —  —  —  —  1,579   —  1,579 Common stock issued, net —  59,975,778   1,128   —  —  —  —  1,128   —  1,128 Stock-based compensation amortization —  —  53   —  —  —  —  53   —  53 Common stock dividends declared —  —  —  —  —  ( 120 ) —  ( 120 ) —  ( 120 ) Preferred stock dividend requirement —  —  —  —  —  ( 37 ) —  ( 37 ) —  ( 37 ) Balance at December 31, 2024 $ 1,579   2,193,573,536   $ 31,555   —   $ —   $ ( 2,966 ) $ ( 19 ) $ 30,149   $ 252   $ 30,401 Net income —  —  —  —  —  2,703   —  2,703   —  2,703 Other comprehensive loss —  —  —  —  —  —  ( 6 ) ( 6 ) —  ( 6 ) Common stock issued, net —  4,369,338   ( 1 ) —  —  —  —  ( 1 ) —  ( 1 ) Stock-based compensation amortization —  —  82   —  —  —  —  82   —  82 Common stock dividends declared —  —  —  —  —  ( 277 ) —  ( 277 ) —  ( 277 ) Preferred stock dividend requirement —  —  —  —  —  ( 110 ) —  ( 110 ) —  ( 110 ) Balance at December 31, 2025 $ 1,579   2,197,942,874   $ 31,636   —   $ —   $ ( 650 ) $ ( 25 ) $ 32,540   $ 252   $ 32,792 See accompanying Notes to the Consolidated Financial Statements. 81 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (in millions) Year ended December 31, 2025 2024 2023 Operating Revenues Electric $ 18,318   $ 17,811   $ 17,424 Natural gas 6,617   6,608   7,004 Total operating revenues 24,935   24,419   24,428 Operating Expenses Cost of electricity 2,609   2,261   2,443 Cost of natural gas 1,107   1,192   1,754 Operating and maintenance 11,337   11,787   11,913 SB 901 securitization charges, net 35   33   1,267 Wildfire-related claims, net of recoveries 100   94   64 Wildfire Fund expense 352   383   567 Depreciation, amortization, and decommissioning 4,634   4,189   3,738 Total operating expenses 20,174   19,939   21,746 Operating Income 4,761   4,480   2,682 Interest income 509   589   593 Interest expense ( 2,713 ) ( 2,781 ) ( 2,485 ) Other income, net 328   319   293 Income Before Income Taxes 2,885   2,607   1,083 Income tax benefit ( 194 ) ( 105 ) ( 1,461 ) Net Income 3,079   2,712   2,544 Preferred stock dividend requirement 14   14   14 Income Available for Common Stock $ 3,065   $ 2,698   $ 2,530 See accompanying Notes to the Consolidated Financial Statements. 82 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions) Year ended December 31, 2025 2024 2023 Net Income $ 3,079   $ 2,712   $ 2,544 Other Comprehensive Income (Loss) Pension and other postretirement benefit plans obligations (net of taxes of $ 4 , $ 3 , and $$ 5 , respectively) ( 8 ) ( 8 ) ( 12 ) Net unrealized gain (losses) on available-for-sale securities (net of taxes of $ 2 , $ 0 , and $ 4 , respectively) 5   1   7 Total other comprehensive income (loss) ( 3 ) ( 7 ) ( 5 ) Comprehensive Income $ 3,076   $ 2,705   $ 2,539 See accompanying Notes to the Consolidated Financial Statements. 83 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (in millions) Balance at December 31, 2025 December 31, 2024 ASSETS Current Assets Cash and cash equivalents $ 353   $ 705 Restricted cash and restricted cash equivalents (includes $ 225 million and $ 263 million related to VIEs at respective dates) 258   272 Accounts receivable Customers (net of allowance for doubtful accounts of $ 408 million and $ 418 million at respective dates) (includes $ 1.9 billion related to VIEs, net of allowance for doubtful accounts of $ 408 million and $ 418 million at respective dates) 2,267   2,220 Accrued unbilled revenue (includes $ 1.3 billion related to VIEs at respective dates) 1,463   1,487 Regulatory balancing accounts 6,300   7,227 Other (net of allowance for doubtful accounts of $ 69 million and $ 35 million at respective dates) 1,725   1,810 Regulatory assets 305   234 Inventories Gas stored underground and fuel oil 75   52 Materials and supplies 745   768 Wildfire Fund asset 297   301 Wildfire self-insurance asset 1,043   905 Other 643   998 Total current assets 15,474   16,979 Property, Plant, and Equipment Property, Plant, and Equipment 128,989   118,262 Construction work in progress 4,626   4,458 Financing lease ROU asset and other 2   814 Total property, plant, and equipment 133,617   123,534 Accumulated depreciation ( 37,269 ) ( 35,304 ) Net property, plant, and equipment 96,348   88,230 Other Noncurrent Assets Regulatory assets 15,981   15,561 Customer credit trust 804   377 Nuclear decommissioning trusts 4,230   3,833 Operating lease ROU asset 445   519 Wildfire Fund asset 3,728   4,070 Other (includes noncurrent accounts receivable of $ 67  million and $ 82 related to VIEs, net of noncurrent allowance for doubtful accounts of $ 15  million and $ 18 at respective dates) 4,073   3,697 Total other noncurrent assets 29,261   28,057 TOTAL ASSETS $ 141,083   $ 133,266 See accompanying Notes to the Consolidated Financial Statements. 84 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (in millions, except share amounts) Balance at December 31, 2025 December 31, 2024 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Short-term borrowings $ 2,675   $ 1,523 Long-term debt, classified as current (includes $ 221 million and $ 222 million related to VIEs at respective dates) 821   2,146 Accounts payable Trade creditors 3,352   2,745 Regulatory balancing accounts 3,119   3,169 Other 844   729 Operating lease liabilities 90   85 Financing lease liabilities —   577 Interest payable (includes $ 72 million and $ 91 million related to VIEs at respective dates) 673   667 Wildfire-related claims 524   916 Other 3,710   3,331 Total current liabilities 15,808   15,888 Noncurrent Liabilities Long-term debt (includes $ 11.7 billion and $ 10.1 billion related to VIEs at respective dates) 51,766   47,958 Regulatory liabilities 20,188   19,417 Pension and other postretirement benefits 482   741 Asset retirement obligations 5,439   5,444 Deferred income taxes 4,732   3,632 Operating lease liabilities 355   434 Financing lease liabilities 2   4 Other 4,474   4,198 Total noncurrent liabilities 87,438   81,828 Shareholders’ Equity Preferred stock 258   258 Common stock, $ 5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates 1,322   1,322 Additional paid-in capital 37,505   35,930 Reinvested earnings ( 1,225 ) ( 1,940 ) Accumulated other comprehensive loss ( 23 ) ( 20 ) Total shareholders’ equity 37,837   35,550 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 141,083   $ 133,266 See accompanying Notes to the Consolidated Financial Statements. 85 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2025 2024 2023 Cash Flows from Operating Activities Net income $ 3,079   $ 2,712   $ 2,544 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 4,634   4,189   3,738 Bad debt expense 402   341   636 Allowance for equity funds used during construction ( 219 ) ( 184 ) ( 179 ) Deferred income taxes and tax credits, net 1,102   1,195   ( 663 ) Wildfire Fund expense 352   383   568 Other ( 158 ) 233   ( 176 ) Effect of changes in operating assets and liabilities: Accounts receivable ( 67 ) ( 1,060 ) ( 361 ) Wildfire-related insurance receivable ( 167 ) 318   358 Inventories —   45   ( 28 ) Accounts payable 112   44   ( 90 ) Wildfire-related claims ( 392 ) ( 506 ) ( 489 ) Other current assets and liabilities 617   ( 235 ) 402 Regulatory assets, liabilities, and balancing accounts, net 173   1,545   ( 429 ) Contributions to Wildfire Fund ( 193 ) ( 193 ) ( 193 ) Other noncurrent assets and liabilities ( 240 ) ( 559 ) ( 541 ) Net cash provided by operating activities 9,035   8,268   5,097 Cash Flows from Investing Activities Capital expenditures ( 11,787 ) ( 10,369 ) ( 9,714 ) Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952   1,980   2,235 Purchases of nuclear decommissioning trust investments ( 1,993 ) ( 2,002 ) ( 2,252 ) Proceeds from sales and maturities of customer credit trust investments 435   398   556 Purchases of customer credit investments ( 742 ) ( 519 ) — Proceeds from sales and maturities of self-insurance investments 1,181   —   — Purchases of self-insurance investments ( 1,384 ) ( 898 ) — Other 22   35   13 Net cash used in investing activities ( 12,316 ) ( 11,375 ) ( 9,162 ) Cash Flows from Financing Activities Borrowings under credit facilities 4,790   6,873   10,675 Repayments under credit facilities ( 1,465 ) ( 10,122 ) ( 10,540 ) Borrowings under term loan 575   —   2,100 Repayments under term loan —   ( 2,100 ) — Short-term debt financing, net of issuance costs of $ 0 , $ 1 , and $ 0 at respective dates —   999   — Short-term debt matured ( 1,000 ) —   — Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $ 38 , $ 1 , and $ 67 at respective dates 4,962   2,999   5,483 Repayment of long-term debt ( 3,876 ) ( 800 ) ( 3,075 ) 86 Proceeds from AB 1054 recovery bonds, net issuance costs of $ 0 , $ 10 , and $ 0 at respective dates —   1,409   — Repayment of AB 1054 recovery bonds ( 88 ) ( 46 ) ( 38 ) Repayment of SB 901 recovery bonds ( 135 ) ( 129 ) ( 130 ) Proceeds from DWR loan —   980   — Preferred stock dividends paid ( 14 ) ( 14 ) ( 14 ) Common stock dividends paid ( 2,350 ) ( 2,025 ) ( 1,775 ) Equity contribution from PG&E Corporation 1,575   5,360   1,290 Other ( 59 ) ( 36 ) 3 Net cash provided by financing activities 2,915   3,348   3,979 Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents ( 366 ) 241   ( 86 ) Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 977   736   822 Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 $ 611   $ 977   $ 736 Less: Restricted cash and restricted cash equivalents ( 258 ) ( 272 ) ( 294 ) Cash and cash equivalents at December 31 $ 353   $ 705   $ 442 Supplemental disclosures of cash flow information Cash paid for: Interest, net of amounts capitalized $ ( 2,359 ) $ ( 2,206 ) $ ( 1,977 ) Supplemental disclosures of noncash investing and financing activities Capital expenditures financed through accounts payable $ 1,859   $ 1,144   $ 1,105 Operating lease liabilities arising from obtaining ROU assets —   1   269 Financing lease liabilities arising from obtaining ROU assets —   43   52 Reclassification of operating lease liabilities to financing lease liabilities —   —   913 DWR loan forgiveness and performance-based disbursements 148   192   214 Capital expenditures financed through current assets and non-current liabilities 592   —   — See accompanying Notes to the Consolidated Financial Statements. 87 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (in millions) Preferred Stock Common Stock Additional Paid-in Capital Reinvested Earnings Accumulated Other Comprehensive Income (Loss) Total Shareholders' Equity Balance at December 31, 2022 $ 258   $ 1,322   $ 29,280   $ ( 3,368 ) $ ( 8 ) $ 27,484 Net income —  —  —  2,544   —  2,544 Other comprehensive loss —  —  —  —  ( 5 ) ( 5 ) Equity contribution —  —  1,290   —  —  1,290 Preferred stock dividend requirement —  —  —  ( 14 ) —  ( 14 ) Common stock dividend —  —  —  ( 1,775 ) —  ( 1,775 ) Balance at December 31, 2023 $ 258   $ 1,322   $ 30,570   $ ( 2,613 ) $ ( 13 ) $ 29,524 Net income —  —  —  2,712   —  2,712 Other comprehensive loss —  —  —  —  ( 7 ) ( 7 ) Equity contribution —  —  5,360   —  —  5,360 Preferred stock dividend requirement —  —  —  ( 14 ) —  ( 14 ) Common stock dividend —  —  —  ( 2,025 ) —  ( 2,025 ) Balance at December 31, 2024 $ 258   $ 1,322   $ 35,930   $ ( 1,940 ) $ ( 20 ) $ 35,550 Net income —  —  —  3,079   —  3,079 Other comprehensive loss —  —  —  —  ( 3 ) ( 3 ) Equity contribution —   —   1,575   —  —  1,575 Preferred stock dividend requirement —   —   —  ( 14 ) —  ( 14 ) Common stock dividend —   —   —  ( 2,350 ) —  ( 2,350 ) Balance at December 31, 2025 $ 258   $ 1,322   $ 37,505   $ ( 1,225 ) $ ( 23 ) $ 37,837 See accompanying Notes to the Consolidated Financial Statements. 88 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION Organization and Basis of Presentation PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  The Utility is primarily regulated by the CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This is a combined annual report of PG&E Corporation and the Utility.  PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated in consolidation.  The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records as regulatory assets costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off. 89 Segment Reporting PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker is the Chief Executive Officer of PG&E Corporation. Net income (loss) is the measure that the chief operating decision maker uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Consolidated Financial Statements. PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information. Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2025 and 2024, the Utility also held $ 258 million and $ 272  million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in Accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass through to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. 90 The following table presents the Utility’s revenues disaggregated by type of customer: Year Ended December 31, (in millions) 2025 2024 2023 Electric Revenue from contracts with customers Residential $ 6,976   $ 7,504   $ 6,041 Commercial 7,022   7,201   5,643 Industrial 1,929   2,065   1,784 Agricultural 1,825   1,815   1,413 Public street and highway lighting 105   103   83 Other, net (1) 72   ( 47 ) 136 Total revenue from contracts with customers - electric 17,929   18,641   15,100 Regulatory balancing accounts (2) 389   ( 830 ) 2,324 Total electric operating revenue $ 18,318   $ 17,811   $ 17,424 Natural gas Revenue from contracts with customers Residential $ 3,651   $ 3,089   $ 3,686 Commercial 1,074   984   1,052 Transportation service only 1,937   1,815   1,603 Other, net (1) 101   159   ( 145 ) Total revenue from contracts with customers - gas 6,763   6,047   6,196 Regulatory balancing accounts (2) ( 146 ) 561   808 Total natural gas operating revenue 6,617   6,608   7,004 Total operating revenues $ 24,935   $ 24,419   $ 24,428 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent alternative revenues authorized to be billed or refunded to customers. Financial Assets Measured at Amortized Cost – Credit Losses PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2025, PG&E Corporation and the Utility have identified the following significant categories of financial assets. Trade Receivables Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates. Expected credit losses of $ 402 million, $ 341  million, and $ 636  million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2025, 2024, and 2023, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $ 278 million and $ 92 million, respectively. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $ 260  million and $ 85  million, respectively. 91 Other Receivables and Available-For-Sale Debt Securities Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss. As of December 31, 2025, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in Current assets – Other and Other noncurrent assets – Other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. Inventories Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or for use as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” below.  The Utility’s estimated service lives of its property, plant, and equipment were as follows: Estimated Service Balance at December 31, (in millions, except estimated service lives) Lives (years) 2025 2024 Electricity generating facilities (1) 1 to 75 $ 11,986   $ 11,420 Electricity distribution facilities 5 to 70 57,174   49,821 Electricity transmission facilities 5 to 80 20,959   18,481 Natural gas distribution facilities 15 to 60 18,240   17,213 Natural gas transmission and storage facilities 15 to 68 11,315   11,117 General plant and other 5 to 50 9,315   10,210 Financing lease 2   814 Construction work in progress 4,626   4,458 Total property, plant, and equipment 133,617   123,534 Accumulated depreciation ( 37,269 ) ( 35,304 ) Net property, plant, and equipment (2) $ 96,348   $ 88,230 (1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. See Note 15 below. Nuclear generating facilities have been fully depreciated by December 31, 2025. (2) Includes $ 2.9  billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. 92 The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and in a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.77 % in 2025 and 3.61 % in 2024. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired asset is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred. Allowance for Funds Used During Construction AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.   The Utility recorded AFUDC related to debt and equity, respectively, of $ 88 million and $ 219 million during 2025, $ 111  million and $ 184  million during 2024, and $ 82  million and $ 179  million during 2023. Asset Retirement Obligations The following table summarizes the changes in ARO during 2025 and 2024, including nuclear decommissioning obligations: (in millions) 2025 2024 ARO liability at beginning of year $ 5,444   $ 5,512 Revision in estimated cash flows ( 274 ) ( 290 ) Accretion 290   269 Liabilities settled ( 21 ) ( 47 ) ARO liability at end of year $ 5,439   $ 5,444 PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below. The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; removal of hazardous materials in some gas transmission assets and restoration of land to the conditions under certain agreements. The total nuclear decommissioning obligation was $ 4.2  billion as of December 31, 2025 and $ 4.0  billion as of December 31, 2024 based on the cost study performed as part of the 2021 NDCTP. The Utility’s ARO assumes that DCPP operates until 2030. The ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals. Disallowance of Plant Costs PG&E Corporation and the Utility recognizes a loss when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. 93 Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at DCPP and the Humboldt Bay independent spent fuel storage installation.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility’s nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC. The cost of debt and equity securities sold by the trust is determined by specific identification. Gains on the nuclear decommissioning trust investments are refundable to customers through rates, and losses are recoverable through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income. Government Assistance The Utility participated in various government assistance programs during the year ended December 31, 2025, 2024, and 2023. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832). Assembly Bill 180 On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the year ended December 31, 2025, the Consolidated Statements of Income reflected $ 13 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $ 56  million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. DWR Loan Agreement On October 18, 2022, the DWR and the Utility entered into a $ 1.4  billion loan agreement to support the extension of DCPP, with up to $ 1.1  billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $ 7 per MWh generated, capped at $ 300  million. The final proceeds were received in 2024, and no further disbursements will be made. The Utility initially accounted for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt . When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred. 94 The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements: (in millions) 2025 2024 2023 Long-term debt: Beginning Balance - DWR loan outstanding $ 886   $ 98   $ 312 Proceeds received —   980   — Operating Expenses: Operating and maintenance expense - Performance-based disbursements ( 21 ) ( 117 ) ( 124 ) Operating and maintenance expense - Loan forgiveness and other adjustments ( 127 ) ( 75 ) ( 90 ) Long-term debt: Ending Balance - DWR loan outstanding $ 738   $ 886   $ 98 U.S. DOE’s Civil Nuclear Credit Program On January 11, 2024, the Utility and the DOE entered into a Credit Award and Payment Agreement for up to $ 1.1  billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $ 65 million, $ 265  million, and $ 115  million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $ 69 million, $ 138  million, and $ 76  million, respectively, as deductions to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIEs Receivables Securitization Program The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Consolidated Balance Sheets. 95 The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2025 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2025 and December 31, 2024, the SPV had net accounts receivable of $ 3.2  billion, and outstanding borrowings of $ 1.8 billion and $ 0 million, respectively, under the Receivables Securitization Program. For more information, see Note 4 below. AB 1054 Securitization PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate Recovery Property. PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2025 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $ 3.26  billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Recovery Funding LLC had outstanding borrowings of $ 3.1 billion and $ 3.2  billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. SB 901 Securitization PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property. PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the year ended December 31, 2025 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate $ 7.5 billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $ 7.1  billion and $ 7.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below. Non-Consolidated VIEs Power Purchase Agreement s Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs as of December 31, 2025, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of December 31, 2025, it did not consolidate any of them. 96 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 estim ates. PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below. In esti mating the life of the fund, PG&E Corporation and the Utility use a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. PG&E Corporation’s and the Utility’s initial estimated life of the fund was 15 years. In 2024, a re-evaluation resulted in the estimated life increasing from 15 to 20 years. The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund. PG&E Corporation and the Utility have an established process to re-evaluate the estimated life of the fund whenever they obtain new significant fire-loss data. PG&E Corporation and the Utility consider significant fire-loss data to include Cal Fire’s annual release of the prior year’s fire-loss data, internally developed data about wildfires and wildfire conditions in their own service area, and other participating electric utilities’ public disclosures of probable and estimable wildfire-related losses in their service area. PG&E Corporation and the Utility are not able to independently verify other utilities’ estimates. During each re-evaluation, PG&E Corporation and the Utility update their assumptions and the dataset of historical fire-losses for wildfires caused by electrical equipment, as applicable. Based upon the outcome of the newly run Monte Carlo simulations, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. PG&E Corporation and the Utility apply adjustments to the estimated life of the fund on a prospective basis. In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable. As of December 31, 2025, PG&E Corporation and the Utility recorded $ 193  million in Other current liabilities, $ 377  million in Other noncurrent liabilities, $ 297  million in Current assets - Wildfire Fund asset, and $ 3.7  billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $ 352 million and $ 383 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Consolidated Statements of Income. PG&E Corporation and the Utility expect to begin accounting for the Continuation Account if the Wildfire Fund administrator determines that the Continuation Account is necessary and the CPUC approves the extension of non-bypassable charges to customers. For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 below. Oakland Headquarters Purchase On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Oakland General Office. The purchase price was $ 906  million, of which the Utility had prepaid a total of $ 400  million. At closing, the Utility assumed a $ 172  million noncurrent liability for a property assessment carried by the property and paid an additional $ 349  million, which was adjusted for closing costs. The cash payment is included within the Capital expenditures line item in PG&E Corporation’s and Utility’s Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities. 97 Other Accounting Policies For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, “Wildfire-Related Contingencies” in Note 14, and “Other Contingencies and Commitments” in Note 15 below. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2025 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Available-for-Sale Securities (2) Total Beginning balance $ ( 35 ) $ 18   $ 3   $ ( 14 ) Other comprehensive income before reclassifications: Unrealized loss on investments (net of taxes of $ 0 , $ 0 and $ 2 , respectively) —   —   5   5 Unrecognized net actuarial gain (loss) (net of taxes of $ 84 , $ 25 and $ 0 , respectively) 215   ( 64 ) —   151 Regulatory account transfer (net of taxes of $ 89 , $ 25 and $ 0 , respectively) ( 228 ) 64   —   ( 164 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (credit) (net of taxes of $ 1 , $ 1 and $ 0 , respectively) (1) ( 2 ) 2   —   — Amortization of net actuarial (gain) loss (net of taxes of $ 1 , $ 6 and $ 0 , respectively) (1) 1   ( 15 ) —   ( 14 ) Regulatory account transfer (net of taxes of $ 1 , $ 5 and $ 0 , respectively) (1) 2   14   —   16 Net current period other comprehensive income ( 12 ) 1   5   ( 6 ) Ending balance $ ( 47 ) $ 19   $ 8   $ ( 20 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details. (2) Includes amounts related to the customer credit trust and self-insurance. 98 The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2024 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Available-for-Sale Securities (2) Total Beginning balance $ ( 28 ) $ 18   $ 2   $ ( 8 ) Other comprehensive income before reclassifications: Unrealized gain on investments (net of taxes of $ 0 , $ 0 and $ 0 , respectively) —   —   1   1 Unrecognized net actuarial gain (loss) (net of taxes of $ 104 , $ 11 and $ 0 , respectively) ( 268 ) 29   —   ( 239 ) Regulatory account transfer (net of taxes of $ 101 , $ 11 and $ 0 , respectively) 260   ( 29 ) —   231 Amounts reclassified from other comprehensive income: Amortization of prior service cost (credit) (net of taxes of $ 1 , $ 1 and $ 0 , respectively) (1) ( 2 ) 2   —   — Amortization of net actuarial (gain) loss (net of taxes of $ 0 , $ 6 and $ 0 , respectively) (1) 1   ( 16 ) —   ( 15 ) Regulatory account transfer (net of taxes of $ 1 , $ 5 and $ 0 , respectively) (1) 2   14   —   16 Net current period other comprehensive income (loss) ( 7 ) —   1   ( 6 ) Ending balance $ ( 35 ) $ 18   $ 3   $ ( 14 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details. (2) Includes amounts related to the customer credit trust and wildfire self-insurance. Recognition of Lease Assets and Liabilities A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless it can ascertain an implicit discount rate from the leasing arrangement. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense as paid in conformity with ratemaking. Financing Leases Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2025, 2024 and 2023, the Utility made total fixed cash payments of $ 26 million, $ 315  million, and $ 142  million, respectively, for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s financing lease ROU assets and lease liabilities related to the lease of the Oakland General Office, which the Utility purchased on June 3, 2025. See “Oakland Headquarters Purchase” above. At December 31, 2025 and 2024, the Utility’s financing leases had a weighted average remaining lease term of 4.1 years and 0.5 years and a weighted average discount rate of 4.6 % and 6.2 %, respectively. 99 The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations: Year Ended December 31, (in millions) 2025 2024 2023 Financing lease fixed cost: Amortization of ROU assets $ 583   $ 274   $ 115 Interest on lease liabilities 16   42   27 Financing lease variable cost ( 1 ) 9   3 Total financing lease costs $ 598   $ 325   $ 145 As of December 31, 2025, the Utility’s future expected financing lease payments are not material. Operating Leases Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2025, 2024, and 2023, the Utility made total cash payments, including fixed and variable, of $ 1.6 billion, $ 1.6  billion, and $ 1.9 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. At December 31, 2025 and 2024, the Utility’s operating leases had a weighted average remaining lease term of 7.1 years and 7.5 years and a weighted average discount rate of 6.6 % and 6.5 %, respectively. The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations: Year Ended December 31, (in millions) 2025 2024 2023 Operating lease fixed cost $ 115   $ 116   $ 269 Operating lease variable cost 1,487   1,524   1,632 Total operating lease costs $ 1,602   $ 1,640   $ 1,901 At December 31, 2025, the Utility’s future expected operating lease payments were as follows: (in millions) December 31, 2025 2026 $ 115 2027 112 2028 98 2029 64 2030 34 Thereafter 165 Total lease payments 588 Less imputed interest ( 143 ) Total $ 445 100 Recently Adopted Accounting Standards Income Taxes In December 2023, the FASB issued ASU No. 2023-09 , Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amended the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. PG&E Corporation and the Utility have applied enhanced disclosure requirements, including, but not limited to, those with respect to PG&E Corporation and the Utility’s income tax rate reconciliation and income taxes paid. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025 and PG&E Corporation and the Utility have applied the enhanced disclosure requirements of ASU 2023-09 on a retrospective basis. Derivatives and Hedging and Revenue from Contracts with Customers In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606 ), which amended the existing guidance to (a) reduce the cost and complexity of evaluating whether contracts with features based on the operations or activities of one of the parties to the contract are derivatives, (b) better portray the economics of those contracts in the financial statements, and (c) reduce diversity in practice resulting from the broad application of the current guidance and changing business environment. The amendments also are expected to reduce diversity in practice by clarifying the applicability of Topic 606, Revenue from Contracts with Customers, to share-based noncash consideration from a customer for the transfer of goods or services. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2025. The adoption of this ASU did not have a significant impact on PG&E Corporation and the Utility’s Consolidated Financial Statements and related disclosures. Accounting Standards Issued But Not Yet Adopted Disaggregation of Income Statement Expenses In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses , which amended the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. Induced Conversions of Convertible Debt Instruments In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. 101 Intangibles – Goodwill and Other – Internal Use Software In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40), which amended the existing guidance to modernize the accounting for software costs that are accounted for under Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software . The amendments in this ASU remove all references to prescriptive and sequential software development stages throughout Subtopic 350-40. Therefore, an entity is required to start capitalizing software costs when both of the following occur: (1) management has authorized and committed to funding the software project, and (2) it is probable that the project will be completed, and the software will be used to perform the function. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. The Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Noncurrent regulatory assets are comprised of the following: Balance at December 31, Recovery Period (in millions) 2025 2024 Pension benefits (1) $ 400   $ 673   Indefinitely Environmental compliance costs 1,158   1,172   32 years Price risk management 100   167 up to 15.5 years Catastrophic event memorandum account (2) 666   742   Various Wildfire-related accounts (3) 1,626   1,697   Various Deferred income taxes (4) 6,157   4,771   Various Financing costs (5) 202   216   Various SB 901 securitization (6) 5,089   5,194   27 years General rate case memorandum accounts (7) —   95   Various Other (8) 583   834   Various Total noncurrent regulatory assets $ 15,981   $ 15,561 (1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. (2 ) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. (3 ) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FRMMA, WMPMA, WMBA, VMBA and MGMA. (4) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings. (6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds to finance $ 7.5  billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $ 7.5  billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $ 2.0  billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below. (7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 included revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022. (8) The balance as of December 31, 2025 includes revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. 102 Regulatory Liabilities Current Regulatory Liabilities At December 31, 2025 and 2024, the Utility had current regulatory liabilities of $ 965  million and $ 1.2 billion respectively. At December 31, 2025, current regulatory liabilities consisted primarily of billed revenues exceeding FERC TO formula rate revenue requirements. Current regulatory liabilities are included within Current liabilities - Other in the Consolidated Balance Sheets. Noncurrent Regulatory Liabilities Noncurrent regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2025 2024 Cost of removal obligations (1) $ 9,488   $ 8,943 Public purpose programs  (2) 1,169   1,112 Employee benefit plans (3) 1,043   1,088 Transmission tower wireless licenses (4) 257   306 SFGO sale (5) —   79 SB 901 securitization (6) 6,010   6,295 Wildfire self-insurance (7) 1,035   804 Other (8) 1,186   790 Total noncurrent regulatory liabilities $ 20,188   $ 19,417 (1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected through rates for expected costs to remove assets. (2) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. (3) Represents cumulative differences between incurred costs and amounts collected through rates for post-retirement medical, post-retirement life, and long-term disability plans. (4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. (5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022. (6) In connection with the SB 901 securitization, the Utility is required to return up to $ 7.59  billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization. See Note 5 below. (7) Represents amounts collected through rates designated for wildfire self-insurance, plus earnings on investments and less operating expenses of wildfire self-insurance. Balance at December 31, 2025 includes amounts collected through both CPUC and FERC rates. Balance at December 31, 2024 includes only amounts collected through CPUC rates. See Note 14 below. (8) Includes amounts collected through FERC rates designated for wildfire self-insurance at December 31, 2024. See Note 14 below. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts fluctuate during the year based on seasonal electric and gas usage and timing differences between when costs are incurred and customer revenues are collected. Some regulatory balancing accounts receivable earn interest which is reflected in Interest income in the Consolidated Statements of Income. Some regulatory balancing accounts payable accrue interest which is reflected in Interest expense in the Consolidated Statements of Income. Interest income from balancing accounts receivable was $ 419  million, $ 537  million, and $ 547  million for the years ended December 31, 2025, 2024, and 2023, respectively. Interest expense from balancing accounts payable was $ 223  million, $ 323  million, and $ 257  million for the years ended December 31, 2025, 2024, and 2023, respectively. 103 Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at December 31, (in millions) 2025 2024 Electric distribution (1) $ 1,465   $ 1,591 Electric transmission (2) 122   117 Gas distribution and transmission (3) 142   387 Energy procurement (4) 2,711   1,066 Public purpose programs (5) 151   162 Wildfire-related accounts (6) 84   979 Insurance premium costs (7) —   38 Residential uncollectibles balancing accounts (8) 278   260 Catastrophic event memorandum account (9) 181   500 General rate case memorandum accounts (10) —   1,113 Other 1,166   1,014 Total regulatory balancing accounts receivable $ 6,300   $ 7,227 Payable Balance at December 31, (in millions) 2025 2024 Electric transmission (2) $ 37   $ 883 Gas distribution and transmission (3) 78   72 Energy procurement (4) 1,502   329 Public purpose programs (5) 472   882 SFGO sale 83   93 Wildfire-related accounts (6) 338   337 Nuclear decommissioning adjustment mechanism (11) 1   23 Other 608   550 Total regulatory balancing accounts payable $ 3,119   $ 3,169 (1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings. (2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases. (3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings. (4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. (5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. (6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA. (7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC. (8) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to limits on electric and gas service disconnections for residential customers. (9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, 2022 WMCE final decision, and 2023 WMCE final decision. (10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023. (11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision. 104 NOTE 4: DEBT Credit Facilities and Term Loans The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2025: (in millions) Termination Date Maximum Facility Limit Loans Outstanding Letters of Credit Outstanding Facility Availability Utility revolving credit facility June 2030 $ 5,400 (1) $ ( 1,575 ) $ ( 639 ) $ 3,186 Utility Receivables Securitization Program (2) June 2027 1,750 (3) ( 1,750 ) —   — (3) PG&E Corporation revolving credit facility June 2028 650   —   —   650 Total credit facilities $ 7,800   $ ( 3,325 ) $ ( 639 ) $ 3,836 (1) Includes a $ 2.0  billion letter of credit sublimit. (2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above. (3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. Utility On April 11, 2025, the Utility amended its existing $ 525  million term loan agreement to extend the maturity date to April 10, 2026. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10 % credit spread adjustment) plus an applicable margin of 1.375 % or (2) the alternative base rate plus an applicable margin of 0.375 %. On June 23, 2025, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 21, 2030, (ii) increase the aggregate commitments from $ 4.4  billion to $ 5.4  billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid. On June 26, 2025, the Utility and the SPV amended the existing $ 1.5  billion Receivables Securitization Program to, among other things, (i) extend the scheduled termination date from June 26, 2026 to June 25, 2027 and (ii) allow the Utility and the SPV to request an increase to the commitments by an additional aggregate amount of up to $ 250  million, subject to the satisfaction of certain terms and conditions. On September 24, 2025, the Utility entered into a Term Loan Credit Agreement, pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $ 500  million (the “Term Loan”). The Term Loan bears interest based on the Utility’s election of either (1) Term SOFR plus an applicable margin of 1.250 % or (2) the alternative base rate plus an applicable margin of 0.250 %. The Utility borrowed the entire amount of the Term Loan on September 24, 2025. The Term Loan has a maturity date of September 23, 2026. On December 19, 2025, the Utility amended its existing $ 525  million term loan agreement to, among other things, (i) increase the borrowing capacity to $ 600  million, (ii) extend the maturity date to December 18, 2026 and (iii) revise the interest rate based on the Utility’s election of either (1) the Term SOFR plus an applicable margin of 1.250 % or (2) the alternative base rate plus an applicable margin of 0.250 %. PG&E Corporation On June 23, 2025, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2028, (ii) increase the aggregate commitments from $ 500  million to $ 650  million and (iii) modify both the interest rate pricing grid and commitment fee pricing grid. 105 Long-Term Debt Issuances and Redemptions Utility On February 24, 2025, the Utility completed the sale of (i) $ 1.0 billion aggregate principal amount of 5.700 % First Mortgage Bonds due 2035 and (ii) $ 750  million aggregate principal amount of 6.150 % First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for (i) the repayment of all of its $ 600  million aggregate principal amount of 3.500 % First Mortgage Bonds due June 15, 2025, and (ii) the repayment of all of its $ 450  million aggregate principal amount of 4.950 % First Mortgage Bonds due June 8, 2025. The Utility used the remaining net proceeds from the offerings for general corporate purposes. On June 4, 2025, the Utility completed the sale of (i) $ 400  million aggregate principal amount of 5.000 % First Mortgage Bonds due 2028, and (ii) $ 850  million aggregate principal amount of 6.000 % First Mortgage Bonds due 2035. The Utility used the net proceeds of such issuances for repayment of a portion of its $ 1.9  billion aggregate principal amount of 3.15 % First Mortgage Bonds due January 1, 2026. On October 2, 2025, the Utility completed the sale of (i) $ 400  million aggregate principal amount of 5.000 % First Mortgage Bonds due 2028, (ii) $ 850  million aggregate principal amount of 5.050 % First Mortgage Bonds due 2032, and (iii) $ 750  million aggregate principal amount of 6.100 % First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for repayment of a portion of its $ 1.9  billion aggregate principal amount of 3.15 % First Mortgage Bonds due January 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes. Convertible Notes On December 4, 2023, PG&E Corporation completed the sale of $ 2.15 billion aggregate principal amount of 4.25 % convertible senior secured notes due December 1, 2027 (the “Convertible Notes”). The Convertible Notes bear interest at an annual rate of 4.25 % with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $ 2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $ 2.15  billion outstanding under its term loan agreement. The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity. Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met: • during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130 % of the conversion price on each applicable trading day; • during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90 % of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or • upon specified distributions and corporate events described in the Convertible Notes Indenture. On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date. 106 On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000. The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $ 23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date. If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100 % of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2025, none of the conditions allowing holders of the Convertible Notes to convert had been met. The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options . Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470. As of December 31, 2025 and 2024, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $ 2.14  billion and $ 2.13  billion, with unamortized debt issuance costs of $ 13  million and $ 20  million, respectively, in Long-term debt. For the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $ 91 million, $ 98  million, and $ 7  million, respectively. 107 The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt: Balance at (in millions) Contractual Interest Rates December 31, 2025 December 31, 2024 PG&E Corporation Convertible Notes due 2027 4.25 % $ 2,150   $ 2,150 Senior Secured Notes due 2028 5.00 % 1,000   1,000 Senior Secured Notes due 2030 5.25 % 1,000   1,000 Junior Subordinated Notes due 2055 7.38 % 1,500   1,500 Unamortized discount, premium and debt issuance costs, net ( 29 ) ( 39 ) Total PG&E Corporation Long-Term Debt 5,621   5,611 Utility First Mortgage Bonds - Stated Maturity: 2025 3.45 % - 4.95 % —   1,925 2026 2.95 % 600   2,551 2027 2.10 % - 5.45 % 3,000   3,000 2028 3.00 % - 5.00 % 2,775   1,975 2029 4.20 % - 6.10 % 2,100   2,100 2030 4.55 % 3,100   3,100 2031 2.50 % - 3.25 % 3,000   3,000 2032 4.40 % - 5.90 % 1,900   1,050 2033 6.15 % - 6.40 % 1,900   1,900 2034 5.80 % - 6.95 % 1,900   1,900 2035 5.70 % - 6.00 % 1,850   — 2040 3.30 % - 4.50 % 2,951   2,951 2041 4.20 % - 4.50 % 700   700 2042 3.75 % - 4.45 % 750   750 2043 4.60 % 375   375 2044 4.75 % 675   675 2045 4.30 % 600   600 2046 4.00 % - 4.25 % 1,050   1,050 2047 3.95 % 850   850 2050 3.50 % - 4.95 % 5,025   5,025 2052 5.25 % 550   550 2053 6.70 % - 6.75 % 2,300   2,300 2054 5.90 % 750   750 2055 6.10 % - 6.15 % 1,500   — Less: current portion, net of unamortized discount and debt issuance costs ( 600 ) ( 1,924 ) Unamortized discount, premium and debt issuance costs, net ( 247 ) ( 226 ) Total Utility First Mortgage Bonds 39,354   36,927 Recovery Bonds (1) 10,145   10,367 Less: current portion ( 221 ) ( 222 ) DWR Loan (2) 738   886 Credit Facilities Receivables Securitization Program - Stated Maturity: 2027 variable rate (3) 1,750   — Total Utility Long-Term Debt 51,766   47,958 Total PG&E Corporation Consolidated Long-Term Debt $ 57,387   $ 53,569 (1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K. (2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance. (3) At December 31, 2025, the contractual SOFR-based interest rate on the Receivables Securitization Program was 5.31 %. 108 Contractual Repayment Schedule PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2025 are reflected in the table below: (in millions, except interest rates) 2026 2027 2028 2029 2030 Thereafter Total PG&E Corporation Average fixed interest rate —   % 4.25   % 5.00   % —   % 5.25   % 7.38   % 5.39   % Fixed rate obligations $ —   $ 2,150   $ 1,000   $ —   $ 1,000   $ 1,500   $ 5,650 Utility (1) Average fixed interest rate 2.95   % 3.22   % 3.99   % 5.52   % 4.55   % 4.90   % 4.69   % Fixed rate obligations $ 600   $ 3,000   $ 2,775   $ 2,100   $ 3,100   $ 28,626   $ 40,201 Variable interest rate as of December 31, 2025 —   % 5.31   % —   % —   % —   % —   % 5.31   % Variable rate obligations $ —   $ 1,750   $ —   $ —   $ —   $ —   $ 1,750 Recovery Bonds (2) AB 1054 obligations $ 81   $ 84   $ 88   $ 91   $ 95   $ 2,633   $ 3,072 SB 901 obligations 140   146   152   159   165   6,311   7,073 Total consolidated debt $ 821   $ 7,130   $ 4,015   $ 2,350   $ 4,360   $ 39,070   $ 57,746 (1) The balance excludes the DWR loan, see Note 2 - Government Assistance. (2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K. NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 11 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Consolidated Statements of Income and had no net impact on Operating revenues for the year ended December 31, 2025. Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $ 5.5  billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $ 7.5  billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $ 2.0  billion in required upfront shareholder contributions to the customer credit trust. As of December 31, 2025, the Utility had made all required upfront contributions. The Utility also recorded a $ 5.54  billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $ 7.59  billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the years ended December 31, 2025 and 2024, the Utility recorded $ 302 million and $ 328  million, respectively, for amortization of the regulatory asset and liability in the Consolidated Statements of Income. The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities: SB 901 securitization regulatory asset (in millions) 2025 2024 Balance at January 1 $ 5,194   $ 5,249 Amortization ( 105 ) ( 55 ) Balance at December 31 $ 5,089   $ 5,194 109 SB 901 securitization regulatory liability (in millions) 2025 2024 Balance at January 1 $ ( 6,295 ) $ ( 6,628 ) Amortization 407   383 Additions (1) ( 122 ) ( 50 ) Balance at December 31 $ ( 6,010 ) $ ( 6,295 ) (1) Includes $ 87  million and $ 16  million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2025 and 2024, respectively. NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 2,197,942,874 shares of common stock outstanding at December 31, 2025, excluding 477,743,590 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2025. On December 4, 2024, PG&E Corporation issued 55,961,070 shares of common stock, no par value, for cash proceeds of approximately $ 1.13  billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan. Dividends CPUC holding company rules require that the Utility’s dividend policy be established by the Utility’s Board of Directors on the same basis as if the Utility were a stand-alone utility company, and that the capital requirements of Utility, as deemed to be necessary to meet the Utility’s electricity service obligations, receive first priority from the Boards of Directors of both PG&E Corporation and the Utility. The CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. California law requires that a corporation must pass either a retained earnings test or an asset to liabilities ratio test to declare a dividend, ensuring it can meet its liabilities as they mature. Additionally, neither PG&E Corporation nor the Utility may pay common stock dividends unless all cumulative preferred dividends on PG&E Corporation’s Mandatory Convertible Preferred Stock and the Utility’s preferred stock, respectively, have been paid. Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s and the Utility’s Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. The following table summarizes the dividends on common stock paid or declared by PG&E Corporation and the Utility in 2025: Security Amount per Share Aggregate amount (in millions) Date of Declaration Record Date Payment Date PG&E Corporation common stock $ 0.025   $ 55   November 29, 2024 December 31, 2024 January 15, 2025 0.025 55   February 20, 2025 March 31, 2025 April 15, 2025 0.025 55   May 22, 2025 June 30, 2025 July 15, 2025 0.025 55   September 18, 2025 September 30, 2025 October 15, 2025 0.05 110   December 11, 2025 December 31, 2025 January 15, 2026 Utility common stock (1) 575   February 20, 2025 (1) March 18, 2025 (1) 575   May 22, 2025 (1) May 30, 2025 (1) 575   September 18, 2025 (1) September 26, 2025 (1) 625   December 11, 2025 (1) December 18, 2025 (1) PG&E Corporation owns all of the outstanding shares of Utility common stock. 110 Long-Term Incentive Plans The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 51,401,320 shares were available for future awards at December 31, 2025. The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards: (in millions) 2025 2024 2023 Restricted stock units 80   67   64 Performance shares 54   31   27 Total compensation expense (pre-tax) $ 134   $ 98   $ 91 Total compensation expense (after-tax) $ 97   $ 71   $ 65 Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Stock Options The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the grant date.  Stock options generally have a 10 -year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2025, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation. The fair value of each stock option on the grant date is estimated using the Black-Scholes valuation method. No stock options were granted in 2025 or 2024. Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the grant date.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the grant date.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior. There was no tax benefit recognized from stock options for the year ended December 31, 2025. The following table summarizes stock option activity for PG&E Corporation and the Utility for 2025: Number of Stock Options Weighted Average Grant- Date Fair Value Weighted Average Remaining Contractual Term (Years) Outstanding at January 1 743,963   $ 10.23 Granted (1) —   — Exercised —   — Forfeited or expired ( 111,495 ) 10.23 Outstanding at December 31 632,468   10.23   1.91 Vested or expected to vest at December 31 632,468   10.23   1.91 Exercisable at December 31 632,468   $ 10.23   1.91 (1) Represents additional payout of existing stock option grants. 111 Restricted Stock Units Restricted stock units generally vest equally over three years . Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2025, 2024, and 2023 was $ 16.43 , $ 16.74 , and $ 15.70 , respectively.  The total fair value of restricted stock units that vested during 2025, 2024, and 2023 was $ 70 million, $ 62 million, and $ 64 million, respectively.  The tax benefit from restricted stock units that vested in 2025 was $ 8 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2025, $ 108 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.60 years. The following table summarizes restricted stock unit activity for 2025: Number of Restricted Stock Units Weighted Average Grant- Date Fair Value Nonvested at January 1 9,423,582   $ 15.52 Granted 6,252,871   16.43 Vested ( 4,744,176 ) 14.66 Forfeited ( 254,623 ) 16.21 Nonvested at December 31 10,677,654   $ 16.42 Performance Shares Performance shares generally vest three years after the grant date.  Following vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three -year performance period (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled. Compensation expense attributable to performance shares is generally recognized ratably over the applicable three -year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-based awards or the grant-date market value of PG&E Corporation common stock for awards based on internal metrics.  The weighted average grant-date fair value for performance shares granted during 2025, 2024, and 2023 was $ 15.10 , $ 16.94 , and $ 13.39 respectively.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2025, $ 39 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.14 years. The following table summarizes activity for performance shares in 2025: Number of Performance Shares Weighted Average Grant- Date Fair Value Nonvested at January 1 7,180,206   $ 15.52 Granted 2,445,690   15.10 Vested ( 2,831,269 ) 11.21 Forfeited ( 332,132 ) 16.39 Nonvested at December 31 6,462,495   $ 16.40 NOTE 7: PREFERRED STOCK PG&E Corporation PG&E Corporation has authorized 400  million shares of preferred stock. On December 5, 2024, PG&E Corporation issued 32,200,000 shares of 6.000 % Series A Mandatory Convertible Preferred Stock, at $ 50.00 per share, for cash proceeds of approximately $ 1.6  billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan. 112 Each share of the Mandatory Convertible Preferred Stock will automatically convert on December 1, 2027. The number of shares of common stock issuable on conversion of Mandatory Convertible Preferred Stock will not be more than 2.4331 shares of common stock and not less than 1.9465 shares of common stock. Other than during a Fundamental Change Conversion Period (as defined in the PG&E Corporation Preferred Stock Certificate of Designation), at any time prior to December 1, 2027, holders of Mandatory Convertible Preferred Stock have the option to elect to convert their shares of the Mandatory Convertible Preferred Stock, in whole or in part (but in no event in increments of less than one share of the Mandatory Convertible Preferred Stock), into shares of common stock at the Minimum Conversion Rate of 1.9465 shares of common stock per share of Mandatory Convertible Preferred Stock, subject to adjustment as described in the Preferred Stock Preliminary Prospectus Supplement. Utility The Utility has authorized 75 million shares of first preferred stock, with a par value of $ 25 per share, and 10 million shares of $ 100 first preferred stock, with a par value of $ 100 per share.  At December 31, 2025 and 2024, the Utility’s preferred stock outstanding included $ 145 million of shares with interest rates between 5 % and 6 % designated as nonredeemable preferred stock and $ 113 million of shares with interest rates between 4.36 % and 5 % that are redeemable between $ 25.75 and $ 27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $ 100 first preferred stock are outstanding. Dividends PG&E Corporation All shares of the Mandatory Convertible Preferred Stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of the Mandatory Convertible Preferred Stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Dividends on the Mandatory Convertible Preferred Stock are cumulative. The Mandatory Convertible Preferred Stock ranks senior to PG&E Corporation’s common stock with respect to the payment of dividends. Accordingly, unless accumulated dividends have been paid on all of the Mandatory Convertible Preferred Stock through the most recently completed dividend period, no dividends may be declared or paid on PG&E Corporation’s common stock and PG&E Corporation will not be permitted to repurchase any of its common stock, subject to limited exceptions. Utility At December 31, 2025, annual dividends on the Utility’s nonredeemable preferred stock ranged from $ 1.25 to $ 1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2025, annual dividends on the Utility’s redeemable preferred stock ranged from $ 1.09 to $ 1.25 per share. Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. 113 The following table summarizes the dividends on preferred stock paid or declared by PG&E Corporation and the Utility in 2025: Security Amount per Share Aggregate amount (in millions) Date of Declaration Record Date Payment Date PG&E Corporation mandatory convertible preferred stock $ 0.7167   $ 23   December 12, 2024 February 14, 2025 February 27, 2025 0.75   24   February 20, 2025 May 15, 2025 May 29, 2025 0.75   24   May 22, 2025 August 15, 2025 August 28, 2025 0.75   24   September 18, 2025 November 14, 2025 December 1, 2025 0.75   24   December 11, 2025 February 13, 2026 March 1, 2026 Utility preferred stock varies by series 3.5   November 29, 2024 January 31, 2025 February 15, 2025 varies by series 3.5   February 20, 2025 April 30, 2025 May 15, 2025 varies by series 3.5   May 22, 2025 July 31, 2025 August 15, 2025 varies by series 3.5   September 18, 2025 October 31, 2025 November 15, 2025 varies by series 3.5   December 11, 2025 January 30, 2026 February 15, 2026 For more information on dividend policy, see Note 6 above. NOTE 8: EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.   The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2025, 2024, and 2023. Year Ended December 31, (in millions, except per share amounts) 2025 2024 2023 Income available for common shareholders $ 2,593   $ 2,475   $ 2,242 Weighted average common shares outstanding, basic (1) 2,197   2,141   2,064 Add incremental shares from assumed conversions: Employee share-based compensation 5   6   6 Equity Units —   —   68 Weighted average common shares outstanding, diluted 2,202   2,147   2,138 Total earnings per common share, diluted $ 1.18   $ 1.15   $ 1.05 (1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility. For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant number of options and securities that were antidilutive. For the year ended December 31, 2025, the calculation of outstanding common shares on a diluted basis excluded the impacts of the Mandatory Convertible Preferred Stock (see Note 7 above), which were antidilutive. In addition, as a result of an irrevocable election made on December 8, 2023 to fix the settlement method to Combination Settlement, the Convertible Notes (as defined in Note 4) did not have a material impact on the calculation of diluted EPS. NOTE 9: INCOME TAXES PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense or tax carryforwards. 114 PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. In general, investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax expense (benefit) were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2025 2024 2023 2025 2024 2023 Current: Federal $ ( 1 ) $ 2   $ ( 1 ) $ ( 1 ) $ 2   $ ( 1 ) State 50   ( 78 ) —   89   ( 78 ) — Deferred: Federal ( 225 ) ( 137 ) ( 1,047 ) ( 171 ) ( 72 ) ( 981 ) State ( 102 ) 15   ( 507 ) ( 109 ) 45   ( 477 ) Federal tax credits ( 2 ) ( 2 ) ( 2 ) ( 2 ) ( 2 ) ( 2 ) Total income tax benefit $ ( 280 ) $ ( 200 ) $ ( 1,557 ) $ ( 194 ) $ ( 105 ) $ ( 1,461 ) 115 The following tables describe net deferred income tax assets and liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2025 2024 2025 2024 Deferred income tax assets: Tax carryforwards $ 9,752   $ 9,429   $ 9,199   $ 8,955 Compensation 211   171   127   86 GHG allowances 457   471   457   471 Wildfire-related claims (1) 227   295   227   295 Operating lease liability 111   78   111   78 Transmission tower wireless license 251   251   251   251 Bad debt 137   127   137   127 Other  (2) 127   140   156   137 Total deferred income tax assets $ 11,273   $ 10,962   $ 10,665   $ 10,400 Deferred income tax liabilities: Property-related basis difference 12,357   11,021   12,344   11,009 Regulatory balancing accounts 487   878   487   878 Income tax regulatory asset (3) 1,723   1,335   1,723   1,335 Debt financing costs 353   390   353   390 Operating lease ROU asset 111   78   111   78 Environmental reserve 288   248   288   248 Other  (4) 89   94   91   94 Total deferred income tax liabilities $ 15,408   $ 14,044   $ 15,397   $ 14,032 Total net deferred income tax liabilities $ 4,135   $ 3,082   $ 4,732   $ 3,632 (1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in the Utility’s service area over the past several years. (2) Amounts include benefits, state taxes, and customer advances for construction. (3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax. (4) Amounts primarily include property taxes. The following tables reconcile income tax expense at the federal statutory rate to the income tax provision: PG&E Corporation Year Ended December 31, (in millions) 2025 2024 2023 Federal statutory income tax rate 21.0   % $ 486   21.0   % $ 478   21.0   % $ 144 Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) ( 1.8 ) ( 41 ) ( 2.0 ) ( 45 ) ( 57.9 ) ( 397 ) Effect of regulatory treatment of fixed asset differences (2) ( 34.2 ) ( 790 ) ( 28.9 ) ( 657 ) ( 62.4 ) ( 428 ) Changes in valuation allowance 0.8   18   ( 0.9 ) ( 20 ) 0.7   5 Nontaxable or nondeductible items 2.2   51   0.8   19   0.2   1 Tax credits ( 1.1 ) ( 26 ) ( 1.0 ) ( 22 ) ( 3.4 ) ( 24 ) Changes in unrecognized tax benefits 0.1   3   2.1   46   0.2   2 Fire Victim Trust (3) —   —   —   —   ( 126.9 ) ( 869 ) Other, net 0.9   19   0.1   1   1.3   9 Effective tax rate ( 12.1 ) % $ ( 280 ) ( 8.8 ) % $ ( 200 ) ( 227.2 ) % $ ( 1,557 ) (1) Includes the effect of state flow-through ratemaking treatment. 116 (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. (3)  Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023. Utility Year Ended December 31, (in millions) 2025 2024 2023 Federal statutory income tax rate 21.0   % $ 606   21.0   % $ 547   21.0   % $ 228 Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) ( 0.6 ) ( 16 ) ( 0.8 ) ( 22 ) ( 34.4 ) ( 373 ) Effect of regulatory treatment of fixed asset differences (2) ( 27.4 ) ( 790 ) ( 25.2 ) ( 657 ) ( 39.5 ) ( 428 ) Changes in valuation allowance —   —   —   —   0.1   1 Nontaxable or nondeductible items 1.1   30   0.4   12   —   — Tax credits ( 0.9 ) ( 26 ) ( 0.9 ) ( 22 ) ( 2.2 ) ( 24 ) Changes in unrecognized tax benefits 0.1   3   1.9   49   0.2   2 Fire Victim Trust (3) —   —   —   —   ( 80.2 ) ( 869 ) Other, net —   ( 1 ) ( 0.4 ) ( 12 ) 0.2   2 Effective tax rate ( 6.7 ) % $ ( 194 ) ( 4.0 ) % $ ( 105 ) ( 134.8 ) % $ ( 1,461 ) (1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. (3)  Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023. Unrecognized Tax Benefits The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2025 2024 2023 2025 2024 2023 Balance at beginning of year $ 454   $ 616   $ 570   $ 454   $ 616   $ 570 Additions for tax position taken during a prior year 5   —   1   5   —   1 Reductions for tax position taken during a prior year ( 7 ) ( 257 ) —   ( 7 ) ( 257 ) — Additions for tax position taken during the current year 665   95   45   665   95   45 Balance at end of year $ 1,117   $ 454   $ 616   $ 1,117   $ 454   $ 616 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2025 for PG&E Corporation and the Utility was $ 102  million. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress. Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2025, 2024, and 2023, these amounts were immaterial. 117 Tax Audits PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The IRS is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $ 850  million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $ 400  million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. On June 4, 2024, the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation decreased its Income tax benefit by $ 70  million related to state and federal income taxes in 2024. PG&E Corporation intends to defend itself vigorously as to all costs in this matter. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, 2025 Expiration Year Federal: Net operating loss carryforward - Pre-2018 $ 3,307   2031 - 2036 Net operating loss carryforward - Post-2017 34,957   N/A Tax credit carryforward 226   Various State: Net operating loss carryforward $ 34,143   2039 - 2041 Tax credit carryforward 167   Various PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards. NOTE 10: DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the Cost of electricity or the Cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Consolidated Balance Sheets at fair value. 118 Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments December 31, 2025 December 31, 2024 Natural Gas (1)  (MMBtus (2) ) Forwards, futures, and swaps 232,825,834   179,257,247 Options 48,215,000   37,717,500 Electricity (MWh) Forwards, futures, and swaps 7,196,942   8,576,078 Options 1,650,800   1,663,200 Congestion Revenue Rights (3) 93,712,644   123,040,895 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements As of December 31, 2025, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Total Derivative Balance Current assets – other $ 165   $ ( 46 ) $ 119 Noncurrent assets – other 170   ( 6 ) 164 Current liabilities – other ( 169 ) 46   ( 123 ) Noncurrent liabilities – other ( 106 ) 6   ( 100 ) Total commodity risk $ 60   $ —   $ 60 As of December 31, 2024, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Total Derivative Balance Current assets – other $ 186   $ ( 16 ) $ 170 Noncurrent assets – other 233   —   233 Current liabilities – other ( 152 ) 16   ( 136 ) Noncurrent liabilities – other ( 167 ) —   ( 167 ) Total commodity risk $ 100   $ —   $ 100 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows. Some of the Utility’s derivative instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2025, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features. NOTE 11: FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, self-insurance assets, trust assets, and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Other inputs that are directly or indirectly observable in the marketplace. 119 • Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At December 31, 2025 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 634   $ —   $ —   $ —  $ 634 Fixed-income securities —   —   —   —  — Self-insurance investments Short-term investments 1,120   —   —   —  1,120 Total Self-insurance investments (2) 1,120   —   —   —   1,120 Nuclear decommissioning trusts Short-term investments 94   —   —   —  94 Global equity securities 2,433   —   —   —  2,433 Fixed-income securities 1,445   1,113   —   —  2,558 Assets measured at NAV —  —  —  —  26 Total nuclear decommissioning trusts (3) 3,972   1,113   —   —   5,111 Customer credit trust Short-term investments 111   —   —   —  111 Global equity securities —   —   —   —  — Fixed-income securities 367   326   —   —  693 Total customer credit trust 478   326   —   —   804 Price risk management instruments (Note 10) Electricity —   19   283   ( 6 ) 296 Gas —   33   —   ( 46 ) ( 13 ) Total price risk management instruments —   52   283   ( 52 ) 283 Rabbi trusts Short-term investments 115   —   —   —  115 Global equity securities 5   —   —   —  5 Life insurance contracts —   65   —   —  65 Total rabbi trusts 120   65   —   —   185 Long-term disability trust Short-term investments 10   —   —   —  10 Assets measured at NAV —  —  —  —  127 Total long-term disability trust 10   —   —   —   137 TOTAL ASSETS $ 6,334   $ 1,556   $ 283   $ ( 52 ) $ 8,274 Liabilities: Price risk management instruments (Note 10) Electricity $ —   $ 80   $ 130   $ ( 6 ) $ 204 Gas —   65   —   ( 46 ) 19 TOTAL LIABILITIES $ —   $ 145   $ 130   $ ( 52 ) $ 223 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements. (2) Includes $ 1 billion and $ 77 million held in the entities for wildfire and non-wildfire self-insurance, respectively. 120 (3) Represents amount before deducting $ 881 million primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2024 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 826   $ —   $ —   $ —  $ 826 Pacific Energy Risk Solutions, LLC Short-term investments 905   —   —   —  905 Total Pacific Energy Risk Solutions, LLC 905   —   —   —  905 Nuclear decommissioning trusts Short-term investments 53   —   —   —  53 Global equity securities 2,228   —   —   —  2,228 Fixed-income securities 1,250   1,027   —   —  2,277 Assets measured at NAV —  —  —  —  22 Total nuclear decommissioning trusts (2) 3,531   1,027   —   —   4,580 Customer credit trust Short-term investments 1   —   —   —  1 Global equity securities 186   —   —   —  186 Fixed-income securities 46   144   —   —  190 Total customer credit trust 233   144   —   —   377 Price risk management instruments (Note 10) Electricity —   26   383   ( 6 ) 403 Gas —   10   —   ( 10 ) — Total price risk management instruments —   36   383   ( 16 ) 403 Rabbi trusts Short-term investments 107   —   —   —  107 Global equity securities 6   —   —   —  6 Life insurance contracts —   66   —   —  66 Total rabbi trusts 113   66   —   —   179 Long-term disability trust Short-term investments 4   —   —   —  4 Assets measured at NAV —  —  —  —  130 Total long-term disability trust 4   —   —   —   134 TOTAL ASSETS $ 5,612   $ 1,273   $ 383   $ ( 16 ) $ 7,404 Liabilities: Price risk management instruments (Note 10) Electricity $ —   $ 37   $ 248   $ ( 6 ) $ 279 Gas —   34   —   ( 10 ) 24 TOTAL LIABILITIES $ —   $ 71   $ 248   $ ( 16 ) $ 303 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements. (2) Represents amount before deducting $ 747  million primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2025 or 2024. 121 Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets, customer credit trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds classified as Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, credit securities, and asset-backed securities. Self-insurance investments Investments held in Pacific Energy Risk Solutions, LLC and Pacific Casualty Insurance Company, LLC primarily include short-term investments that are U.S. government securities classified as Level 1. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Uncertainty Analysis Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. 122 Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments.  See Note 10 above. Fair Value (in millions) At December 31, 2025 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 252   $ 83   Market approach CRR auction prices $ ( 74 ) - 74 / 2 Power purchase agreements $ 31   $ 47   Discounted cash flow Forward prices $ 11 - 106 / 53 (1)  Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value (in millions) At December 31, 2024 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 366   $ 121   Market approach CRR auction prices $ ( 951 ) - 50,044 / 2 Power purchase agreements $ 17   $ 127   Discounted cash flow Forward prices $ 0 - 126 / 47 (1)  Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Level 3 Reconciliation The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2025 and 2024: Price Risk Management Instruments (in millions) 2025 2024 Asset balance as of January 1 $ 127   $ 191 Net realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts (1) 26   ( 64 ) Asset balance as of December 31 $ 153   $ 127 (1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets, and net income is not impacted. Financial Instruments PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, and customer deposits approximate their carrying values as of December 31, 2025 and December 31, 2024, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2025 At December 31, 2024 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation (1) $ 5,360   $ 5,697   $ 5,358   $ 5,829 Utility 38,145   35,565   37,812   34,532 (1) As of December 31, 2025, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $ 2.1 billion and $ 2.2 billion, respectively. 123 Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Cost Total Unrealized Gains Total Unrealized Losses Total Fair Value As of December 31, 2025 Nuclear decommissioning trusts Short-term investments $ 94   $ —   $ —   $ 94 Global equity securities 324   2,140   ( 5 ) 2,459 Fixed-income securities 2,557   48   ( 47 ) 2,558 Total (1) $ 2,975   $ 2,188   $ ( 52 ) $ 5,111 As of December 31, 2024 Nuclear decommissioning trusts Short-term investments $ 54   $ —   $ ( 1 ) $ 53 Global equity securities 353   1,907   ( 10 ) 2,250 Fixed-income securities 2,341   20   ( 84 ) 2,277 Total  (1) $ 2,748   $ 1,927   $ ( 95 ) $ 4,580 (1) Represents amounts before deducting $ 881  million and $ 747  million as of December 31, 2025 and December 31, 2024, respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2025 Less than 1 year $ 95 1–5 years 822 5–10 years 564 More than 10 years 1,077 Total maturities of fixed-income securities $ 2,558 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2025 2024 2023 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 1,952   $ 1,980   $ 2,235 Gross realized gains on securities 213   255   80 Gross realized losses on securities ( 25 ) ( 63 ) ( 74 ) 124 Customer Credit Trust The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Cost Total Unrealized Gains Total Unrealized Losses Total Fair Value As of December 31, 2025 Customer credit trust Short-term investments $ 111   $ —   $ —   $ 111 Global equity securities —   —   —   — Fixed-income securities 689   5   ( 1 ) 693 Total $ 800   $ 5   $ ( 1 ) $ 804 As of December 31, 2024 Customer credit trust Short-term investments $ 1   $ —   $ —   $ 1 Global equity securities 161   28   ( 3 ) 186 Fixed-income securities 193   1   ( 4 ) 190 Total $ 355   $ 29   $ ( 7 ) $ 377 The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2025 Less than 1 year $ 290 1–5 years 107 5–10 years 49 More than 10 years 247 Total maturities of fixed-income securities $ 693 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2025 2024 2023 Proceeds from sales and maturities of customer credit trust investments $ 435   $ 398   $ 556 Gross realized gains on securities 131   10 $ 23 Gross realized losses on securities ( 20 ) ( 8 ) $ ( 19 ) NOTE 12: EMPLOYEE BENEFIT PLANS Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”) PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  Certain trusts underlying these plans are qualified trusts under the IRC.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates. PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans. 125 Change in Plan Assets, Benefit Obligations, and Funded Status The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2025 and 2024: Pension Plan (in millions) 2025 2024 Change in plan assets: Fair value of plan assets at beginning of year $ 16,767   $ 17,211 Actual return on plan assets 1,779   218 Company contributions 337   337 Benefits and expenses paid ( 1,020 ) ( 999 ) Fair value of plan assets at end of year $ 17,863   $ 16,767 Change in benefit obligation: Benefit obligation at beginning of year $ 17,585   $ 17,697 Service cost for benefits earned 424   396 Interest cost 1,007   916 Actuarial loss (gain) (1) 427   ( 424 ) Benefits and expenses paid ( 1,020 ) ( 1,000 ) Benefit obligation at end of year (2) $ 18,423   $ 17,585 Funded Status: Current liability $ ( 10 ) $ ( 10 ) Noncurrent liability ( 550 ) ( 808 ) Net liability at end of year $ ( 560 ) $ ( 818 ) (1) The actuarial loss for the year ended December 31, 2025 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in demographic assumptions; the actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions. (2) PG&E Corporation’s accumulated benefit obligation was $ 16.5 billion and $ 15.8 billion at December 31, 2025 and 2024, respectively. 126 Postretirement Benefits Other than Pensions (in millions) 2025 2024 Change in plan assets: Fair value of plan assets at beginning of year $ 2,471   $ 2,499 Actual return on plan assets 200   74 Company contributions 7   5 Plan participant contribution 91   84 Benefits and expenses paid ( 196 ) ( 191 ) Fair value of plan assets at end of year $ 2,573   $ 2,471 Change in benefit obligation: Benefit obligation at beginning of year $ 1,279   $ 1,377 Service cost for benefits earned 38   41 Interest cost 73   71 Actuarial loss (gain) (1) 125   ( 123 ) Benefits and expenses paid ( 182 ) ( 174 ) Federal subsidy on benefits paid 4   3 Plan participant contributions 91   84 Benefit obligation at end of year $ 1,428   $ 1,279 Funded Status: (2) Noncurrent asset $ 1,144   $ 1,192 Noncurrent liability —   — Net asset at end of year $ 1,144   $ 1,192 (1) The actuarial loss for the year ended December 31, 2025 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations and unfavorable changes in claims cost, medical trends, and demographic assumptions. The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets. (2) At December 31, 2025 and 2024, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $ 274 million and $ 322 million as of December 31, 2025, and $ 261 million and $ 296 million as of December 31, 2024, respectively. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Net Periodic Benefit Cost PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Plan” below.  Post-retirement medical and life insurance plans are included in “Postretirement Benefits Other than Pensions” below. 127 Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows: Pension Plan (in millions) 2025 2024 2023 Service cost for benefits earned  (1) $ 424   $ 396   $ 379 Interest cost 1,007   916   913 Expected return on plan assets ( 1,053 ) ( 1,014 ) ( 981 ) Amortization of prior service cost ( 3 ) ( 3 ) ( 4 ) Amortization of net actuarial loss 2   1   1 Net periodic benefit cost 377   296   308 Less: transfer to regulatory account (2) ( 40 ) 39   25 Total expense recognized $ 337   $ 335   $ 333 (1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits. (2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates. Postretirement Benefits Other than Pensions (in millions) 2025 2024 2023 Service cost for benefits earned  (1) $ 38   $ 41   $ 38 Interest cost 73   71   73 Expected return on plan assets ( 150 ) ( 139 ) ( 132 ) Amortization of prior service cost 3   3   3 Amortization of net actuarial gain ( 23 ) ( 23 ) ( 19 ) Net periodic benefit cost $ ( 59 ) $ ( 47 ) $ ( 37 ) (1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits. Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Accumulated Other Comprehensive Income PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of Accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to Accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to Accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in Accumulated other comprehensive income (loss). 128 Valuation Assumptions The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs. Pension Plan PBOP Plans December 31, December 31, 2025 2024 2023 2025 2024 2023 Discount rate 5.58   % 5.76   % 5.21   % 5.51 - 5.60 % 5.71 - 5.76 % 5.18 - 5.22 % Rate of future compensation increases 4.80   % 4.80   % 3.80   % N/A N/A N/A Expected return on plan assets 7.00   % 6.40   % 6.00   % 4.30 - 7.20 % 3.90 - 7.20 % 3.70 - 7.00 % Interest crediting rate for cash balance plan 4.23   % 4.41   % 3.86   % N/A N/A N/A The assumed health care cost trend rate as of December 31, 2025 was 7.00 %, gradually decreasing to the ultimate trend rate of approximately 4.5 % in 2036 and beyond. Expected rates of return on plan assets were developed by estimating future asset class returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 7.0 % compares to a ten-year actual return of 5.7 %.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 831 Aa-grade non-callable bonds at December 31, 2025.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. Investment Policies and Strategies The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility.  In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include private real estate funds. Absolute return investments include hedge fund portfolios. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the allocation between fixed income and equity of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non-U.S. dollar exposure of global equity investments. 129 The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2026 2025 2024 2026 2025 2024 Global equity securities 28   % 26   % 26   % 14   % 30   % 29   % Absolute return 1   1   1   —   —   — Real assets 6   8   8   3   3   3 Fixed-income securities 65   65   65   83   67   68 Total 100   % 100   % 100   % 100   % 100   % 100   % PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. Fair Value Measurements The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2025 and 2024. Fair Value Measurements At December 31, 2025 2024 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 452   $ 30   $ —   $ 482   $ 126   $ 47   $ —   $ 173 Global equity securities 1,445   —   —   1,445   1,310   —   —   1,310 Real assets 2   —   —   2   437   —   —   437 Fixed-income securities 1,990   6,880   12   8,882   2,180   6,367   16   8,563 Assets measured at NAV —  —  —  7,052   —  —  —  6,284 Total $ 3,889   $ 6,910   $ 12   $ 17,863   $ 4,053   $ 6,414   $ 16   $ 16,767 PBOP Plans: Short-term investments $ 546   $ —   $ —   $ 546   $ 27   $ —   $ —   $ 27 Global equity securities 2   —   —   2   60   —   —   60 Real assets —   —   —   —   20   —   —   20 Fixed-income securities 518   561   —   1,079   431   751   1   1,183 Assets measured at NAV —  —  —  946   —  —  —  1,181 Total $ 1,066   $ 561   $ —   $ 2,573   $ 538   $ 751   $ 1   $ 2,471 Total plan assets at fair value       $ 20,436         $ 19,238 Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days. Short-Term Investments Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets. 130 Global Equity Securities The global equity category includes investments in common stock and equity-index futures.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets. Real Assets The real asset category includes portfolios of private real estate funds. These funds are measured at NAV as a practical expedient. Fixed-Income Securities Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities. Transfers Between Levels No material transfers between levels occurred in the years ended December 31, 2025 or 2024. 131 Level 3 Reconciliation The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2025 and 2024: (in millions) For the year ended December 31, 2025 Fixed-Income Balance at beginning of year $ 16 Actual return on plan assets: Relating to assets still held at the reporting date 7 Relating to assets sold during the period ( 7 ) Purchases, issuances, sales, and settlements: Purchases 6 Settlements ( 10 ) Balance at end of year $ 12 (in millions) For the year ended December 31, 2024 Fixed-Income Balance at beginning of year $ 13 Actual return on plan assets: Relating to assets still held at the reporting date 9 Relating to assets sold during the period ( 9 ) Purchases, issuances, sales, and settlements: Purchases 14 Settlements ( 11 ) Balance at end of year $ 16 There were no material transfers out of Level 3 in 2025 or 2024. Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $ 337 million to the pension benefit plans, $ 31  million to the long-term disability trusts, and $ 7 million to the other postretirement benefit plans in 2025.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. The Utility’s pension benefits met all funding requirements under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation and the Utility expect to make total contributions of approximately $ 327  million to the qualified pension plan in 2026. PG&E Corporation and the Utility plan to contribute $ 31  million to the long-term disability trusts in 2026, as authorized in the 2023 GRC. Benefits Payments and Receipts As of December 31, 2025, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension Plan PBOP Plans Federal Subsidy 2026 993   84   ( 1 ) 2027 1,082   86   ( 1 ) 2028 1,110   90   ( 1 ) 2029 1,136   93   ( 1 ) 2030 1,161   96   ( 1 ) 2031-2035 6,159   523   ( 6 ) 132 There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and the Utility for the years presented above. Retirement Savings Plan PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan and provides for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $ 194 million, $ 175  million, and $ 158  million in 2025, 2024, and 2023, respectively. PG&E Corporation’s default matching contributions under its 401(k) plan are in cash. There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above. NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) plus five percent of direct labor costs or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are priced at the lower of fully loaded cost or fair market value. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies. NOTE 14: WILDFIRE-RELATED CONTINGENCIES Liability Overview PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. 133 Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent. The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. Claims related to the 2019 Kincade fire are subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through December 31, 2025. Payments (in millions) 2019 Kincade Fire $ 1,287 2021 Dixie Fire 1,908 2022 Mosquito Fire 107 Total at December 31, 2025 $ 3,302 134 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons. On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire. As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 3,014 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024, the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication. On October 11, 2022, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $ 1.225 billion as of December 31, 2024 (before available insurance). In each of the first and second quarters of 2025, PG&E Corporation and the Utility recorded additional charges of $ 50  million, for an aggregate liability of $ 1.325 billion (before available insurance). PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include any claims related to Cal OES or any punitive damages. The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2024. Loss Accrual (in millions) Balance at December 31, 2024 $ 267 Accrued Losses 100 Payments ( 329 ) Balance at December 31, 2025 $ 38 The Utility has fully collected its liability insurance coverage for third-party liability attributable to the 2019 Kincade fire, which was for an aggregate amount of $ 430 million. As of December 31, 2025, the Utility received $ 111 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. 135 2021 Dixie Fire According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire. On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, through its ongoing investigation, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it. As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 189 complaints on behalf of at least 9,034 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A trial with respect to one plaintiff has been scheduled for December 2, 2026. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025. No bellwether trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates. Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On April 30, 2025, in response to the Court of Appeal’s request, Cal Fire filed an opposition to the Utility’s writ. The Utility filed a reply to the opposition on May 9, 2025. As of February 4, 2026, the writ remains pending with the Court of Appeal. On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect. PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, and the hearing date on the motion is scheduled for June 18, 2026. 136 Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $ 1.925 billion as of December 31, 2024 (before available recoveries). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2025 of $ 225 million, of which $ 25  million was recorded in the fourth quarter, for an aggregate liability of $ 2.150 billion (before available recoveries). PG&E Corporation’s and the Utility’s accrued estimated losses of $ 2.150  billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable. As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $ 650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests. The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2024. Loss Accrual (in millions) Balance at December 31, 2024 $ 567 Accrued Losses 225 Payments ( 549 ) Balance at December 31, 2025 $ 243 As of December 31, 2025, the Utility recorded an insurance receivable of $ 521 million for probable insurance recoveries in connection with the 2021 Dixie fire. The Utility recorded an aggregate Wildfire Fund receivable of $ 1.150 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $ 851 million as of December 31, 2025. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of December 31, 2025, the Utility also recorded a $ 97 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $ 535 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. 137 2022 Mosquito Fire On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100 % contained. The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause. The cause of the 2022 Mosquito fire remains under investigation by the USFS, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is ongoing. As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 35 complaints on behalf of at least 2,939 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and a group of six public entities have each filed complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into settlement agreements with five public entities. The court has set individual claimant bellwether trial dates for April 13, 2026. On May 28, 2025, the Utility executed an amendment to a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect. On August 21, 2025, Cal Fire filed a complaint against the Utility for fire suppression and investigation costs. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $ 100 million as of December 31, 2024 (before available recoveries). During 2025, PG&E Corporation and the Utility recorded additional charges of $ 250  million, of which $ 100  million was recorded in the fourth quarter, for an aggregate liability of $ 350 million (before available recoveries). PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable. As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire. 138 The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2024. Loss Accrual (in millions) Balance at December 31, 2024 $ 82 Accrued Losses 250 Payments ( 89 ) Balance at December 31, 2025 $ 243 As of December 31, 2025, the Utility recorded an insurance receivable of $ 363 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of December 31, 2025, the Utility also recorded a $ 7 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $ 54 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.” Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2025 are: Potential Recovery Source (in millions) 2021 Dixie fire 2022 Mosquito fire Insurance $ 521   $ 363 FERC TO rates 97   7 WEMA 535   54 Wildfire Fund 1,150   — Probable recoveries at December 31, 2025 (1) $ 2,303   $ 424 (1) Includes legal costs of $ 148 million and $ 73 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2025. The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Insurance Self-Insurance Since August 2023, the Utility’s wildfire liability insurance for amounts up to $ 1.0  billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5 % deductible, capped at a maximum of $ 50  million, on claims that are incurred each year. Insurance Receivable As of December 31, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $ 521 million and $ 363 million in connection with the 2021 Dixie fire and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. 139 The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2024: Insurance Receivable (in millions) 2021 Dixie fire 2022 Mosquito fire Total Balance at December 31, 2024 $ 27   $ 90   $ 117 Accrued insurance recoveries ( 6 ) 273   267 Reimbursements ( 20 ) ( 82 ) ( 102 ) Balance at December 31, 2025 $ 1   $ 281   $ 282 Regulatory Recovery Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.” The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable. FERC TO Rates The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2025, the Utility recorded reductions of $ 97 million and $ 7 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate. WEMA The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of December 31, 2025, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery, and the Utility recorded $ 535 million and $ 54 million, respectively, as regulatory assets in the WEMA. 140 Wildfire Fund Recoveries under AB 1054 and SB 254 AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate arising from wildfires in any coverage year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of December 31, 2025 reflects an expectation that the coverage year will be based on the calendar year. Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $ 4.7  billion for 2025. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2025 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable. Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The Wildfire Fund is expected to be capitalized with at least $ 21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $ 7.5  billion in initial contributions from California’s three large electric IOUs and (iii) $ 300  million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $ 18  billion, of which $ 9  billion would be contributed through a non-bypassable charge from customers, $ 5.1  billion would be contributed by the utilities, and an additional $ 3.9  billion would be contributed by the utilities if the administrator determines that additional contributions are needed. The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20 -year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. AB 1054 authorizes the payment of funds to a participating utility where that utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims. 141 PG&E Corporation and the Utility’s Wildfire Fund recoveries are reflected in Wildfire-related claims, net of recoveries in the Consolidated Statements of Income to the extent PG&E Corporation and the Utility determine that it is probable the CPUC will conclude that the Utility’s conduct was just and reasonable or when the Utility is not otherwise required to reimburse the Wildfire Fund. As of December 31, 2025, PG&E Corporation and the Utility recorded $ 295 million and $ 4 million in Accounts receivable - Other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2024: Wildfire Fund Receivable (in millions) 2021 Dixie fire Balance at December 31, 2024 $ 756 Accrued Wildfire Fund recoveries 225 Claims paid by Wildfire Fund ( 682 ) Balance at December 31, 2025 $ 299 For more information, see Note 2 above. Wildfire-Related Securities Litigation As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.” Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $ 300  million, which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount due to the number of plaintiffs and the complexity of the litigation. Wildfire-Related Securities Claims in District Court In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al . The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed the Public Employee Retirement Association of New Mexico (“PERA”) as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program. On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation. 142 On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint. On January 10, 2026, PERA filed a motion for preliminary approval of a $ 100  million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. A hearing on the motion for preliminary approval in the District Court is scheduled for February 26, 2026. Putative class members would have the right to opt out of the proposed settlement. On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al. , alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation . Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from the trading of debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”). While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, these defenses may not prevail and proceeds from any insurance may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy any such allowed claims as follows: • each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and • each holder of an allowed Subordinated Debt Claim will receive payment in full, in cash. PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. Such claims could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 143 Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19 % of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date. On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims. Indemnification Obligations To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions. PG&E Corporation and the Utility additionally may have indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things. NOTE 15: OTHER CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve a series of complex judgments about future events.  Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  See “Purchase Commitments” below.  PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. CPUC Matters Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $ 2.5  billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs. The recorded expenditures for wildfire mitigation consist of $ 726  million in expenses and $ 1.5  billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $ 120  million in expenses and $ 118  million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $ 688  million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. 144 On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $ 516  million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $ 172  million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund. Other Matters PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Estimated liabilities for contingencies related to such matters totaled $ 151 million and $ 74 million as of December 31, 2025 and 2024 , respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14 above. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Environmental Remediation Contingencies Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following: Balance at (in millions) December 31, 2025 December 31, 2024 Topock natural gas compressor station $ 315   $ 294 Hinkley natural gas compressor station 99   97 Former MGP sites owned by the Utility or third parties (1) 715   782 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 71   76 Fossil fuel-fired generation facilities and sites (3) 17   18 Total environmental remediation liability $ 1,217   $ 1,267 (1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street. (2) Primarily driven by Geothermal Landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant. The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. 145 The Utility’s environmental remediation liability as of December 31, 2025, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  As of December 31, 2025, the Utility expected to recover $ 1.0 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available. Balance at December 31, 2025 (in millions) Low end of the range High end of the range HSMA Recovery (1) Topock natural gas compressor station (2) $ 315   $ 518   Available Hinkley natural gas compressor station (2) 99   221   Unavailable Former MGP sites owned by the Utility or third parties (3) 715   1,292   Available Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4) 71   146   Available Fossil fuel-fired generation facilities and sites (5) 17   32   Unavailable (1) For sites where HSMA recovery is available, the Utility expects to recover 90 % of the costs associated with environmental remediation through rates. (2) The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years. (3) Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. (4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. (5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site. Nuclear Insurance The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and European Mutual Association for Nuclear Insurance (“EMANI”), covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at DCPP. NEIL provides property damage and business interruption coverage of up to $ 3.2  billion per nuclear incident and $ 2.5  billion per non-nuclear incident for DCPP. For Humboldt Bay independent spent fuel storage installation, NEIL provides up to $ 50  million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $ 3.2  billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. EMANI shares losses with NEIL as part of the first $ 400  million of coverage within the current nuclear insurance program. EMANI also provides an additional $ 200  million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $ 43  million. Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $ 16.3  billion. The Utility purchases the maximum available public liability insurance of $ 500  million for DCPP. The balance of the $ 16.3  billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $ 332  million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $ 49  million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years . 146 The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $ 500  million per incident. In addition, the Utility has approximately $ 53  million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $ 500  million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, covering liabilities in excess of the $ 53  million in liability insurance. Purchase Commitments The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2025: Power Purchase Agreements (in millions) Renewable Energy Conventional Energy Natural Gas Other (1) Total 2026 $ 1,937   $ 1,058   $ 544   $ 278   $ 3,817 2027 1,921   1,035   193   134   3,283 2028 1,903   989   106   47   3,045 2029 1,858   905   98   6   2,867 2030 1,852   510   42   2   2,406 Thereafter 12,828   4,315   34   5   17,182 Total purchase commitments $ 22,299   $ 8,812   $ 1,017   $ 472   $ 32,600 (1) Includes other power purchase agreements and nuclear fuel agreements. Third-Party Power Purchase Agreements In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, qualifying facilities (“QF”) agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery. Renewable Energy Power Purchase Agreements In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  These renewable energy contracts expire at various dates between 2026 and 2047. Conventional Energy Power Purchase Agreements The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2026 and 2044. Other Power Purchase Agreements The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2025, QF contracts in operation expire at various dates between 2026 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power. The net costs incurred for all power purchases and electric capacity were $ 2.0 billion in 2025, $ 2.1 billion in 2024, and $ 2.4 billion in 2023. 147 Natural Gas Supply, Transportation, and Storage Commitments The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers, and to fuel its owned-generation facilities along with a facility associated with a third party tolling agreement.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the United States Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2026 and 2035.  In addition, the Utility has contracted for natural gas storage services in Northern California and Canada to more reliably meet customers’ loads. Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, were $ 1.0 billion in 2025, $ 0.8 billion in 2024, and $ 2.5 billion in 2023. Nuclear Fuel Agreements The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2026 and 2030 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. Payments for nuclear fuel were $ 134 million in 2025, $ 294 million in 2024, and $ 180 million in 2023. Other Commitments PG&E Corporation and the Utility have other commitments primarily related to office facilities leases and land leases which expire at various dates between 2026 and 2054, as well as other multi-year agreements.  At December 31, 2025, the future minimum payments related to these commitments were as follows: (in millions) Other Commitments 2026 $ 82 2027 51 2028 41 2029 39 2030 13 Thereafter 65 Total minimum payments $ 291 Payments for other commitments were $ 63 million in 2025, $ 105 million in 2024, and $ 106 million in 2023.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years . In addition to the commitments in the table above, if the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution to the customer credit trust of up to $ 775  million in 2040. The Utility also will share with customers 25 % of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).  PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP.  Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements. 148 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of internal control over financial reporting as of December 31, 2025, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2025. Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control  — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 149