OVERVIEW This is a combined Form 10-Q of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1. It should also be read in conjunction with the 2025 Form 10-K. Generally, PG&E Corporation’s and the Utility’s revenues vary based on the outcomes of ratemaking proceedings and the amount of pass-through costs incurred. See “Ratemaking Mechanisms” in Part I, Item 1: “Business” in the 2025 Form 10-K regarding how the Utility’s revenues are determined. Factors that cause costs to vary include the cost of purchased power and fuel; the costs of procurement, storage, and transportation of natural gas; weather; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances or changes in interest rates. The discussions related to the results of operations and liquidity for the three and six months ended June 30, 2025 compared to the same periods in 2024 are incorporated by reference to Part I, Item 2: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PG&E Corporation’s and the Utility’s combined Form 10-Q for the three and six months ended June 30, 2025, which was filed with the SEC in July 2025. Key Factors Affecting Financial Results PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors: •The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, self-insurance, the Wildfire Fund, the Continuation Account, and regulatory recovery. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include Enhanced Powerline Safety Settings (“EPSS”), PSPS, vegetation management, asset inspections, system hardening, situational awareness tools, and ignition response. These initiatives reduce but do not eliminate the Utility’s wildfire risk. Despite these extensive measures, the Utility’s equipment may still be involved in the ignition of future wildfires, including catastrophic wildfires. This risk is exacerbated by a variety of factors, including climate change and severe weather events (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), as well as infrastructure and vegetation conditions. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is determined primarily by environmental and vegetation conditions, third-party suppression efforts, and the location of the wildfire. The financial impact of past wildfires has been significant. In addition to significant liabilities incurred for past wildfires, PG&E Corporation and the Utility have and will continue to incur substantial expenditures in connection with these initiatives. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts. PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. 10 If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund or Continuation Account coverage year (“Coverage Year”), the Wildfire Fund or the Continuation Account, as applicable, may be available to reimburse the Utility such excess amount. The Utility’s ability to recover wildfire costs depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Wildfire Fund or the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable. With respect to the Wildfire Fund, PG&E Corporation and the Utility expect to re-evaluate the reasonableness of the currently estimated 20-year life and recognize accelerated amortization of the Wildfire Fund asset based on reliable, publicly available information. SCE has disclosed that a liability for the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”) is probable, but a range of losses that may be incurred is not reasonably estimable. In the first quarter of 2026, SCE has also disclosed losses of $1.3 billion and a Wildfire Fund receivable of $295 million based on their recent settlement activity. As of June 30, 2026, PG&E Corporation and the Utility continue to use an estimated 20-year life and recognized accelerated amortization of $78 million. With respect to the Continuation Account, additional uncertainties include whether the Wildfire Fund administrator determines that the Continuation Account is necessary, whether the CPUC authorizes extending the non-bypassable charge, whether the administrator determines that additional contributions are needed and, if so, the timing of those contingent contributions. The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The CPUC could interpret the revised prudency standard under AB 1054 or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover some or all of the expenses that it has recorded as receivables. As of June 30, 2026, the Utility has recorded receivables for regulatory recovery of $638 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. The Utility also received $128 million from the Wildfire Fund related to the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”). The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. For more information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 regarding the Wildfire Fund asset, Note 3 regarding expenditures incurred for wildfire mitigation, “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 10 regarding wildfire liabilities, “Loss Recoveries” in Note 10 regarding recoveries, and “Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application” in “Regulatory Matters” below. •The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Regulatory Matters” below. 11 There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented or if there is a failure to act on wildfire matters, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition.  In particular, California lawmakers are considering potential legislation in the legislative session scheduled to end August 31, 2026 that could impact PG&E Corporation and the Utility. If there is insufficient legislative action on wildfire matters, PG&E Corporation and the Utility could face persistent financial limitations and elevated risk, including challenges obtaining financing on acceptable terms or increased financing needs, which in turn may negatively impact their financial results and customer affordability. Without sufficient legislation, PG&E Corporation and the Utility may consider changes to their financial plan, including capital allocation priorities. •PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results. For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above. Tax Matters PG&E Corporation’s ability to use its U.S. federal and California state net operating loss carryforwards and certain other tax attributes may be significantly limited if the ownership of PG&E Corporation’s stock by certain shareholders increases beyond statutory thresholds. To reduce the possibility of such a limitation, PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and PG&E Corporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock.  These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles), in excess of certain thresholds based on the amount and relative value of such stock without approval by the Board of Directors of PG&E Corporation.  The computation of the applicable threshold is complex and may vary from date to date; the threshold of the combined value of PG&E Corporation common and mandatory convertible preferred stock was approximately 3.92% as of July 15, 2026. For more information about these restrictions that affect the ownership of PG&E Corporation stock, see “Tax Matters” in Part II, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2025 Form 10-K. RESULTS OF OPERATIONS The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and six months ended June 30, 2026 and 2025. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations. 12 PG&E Corporation The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of income (loss) attributable to common shareholders for the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, Net Change Percentage Change Six Months Ended June 30, Net Change Percentage Change (in millions) 2026 2025 2026 2025 Consolidated Total $ 733 $ 521 $ 212 41 % $ 1,591 $ 1,128 $ 463 41 % PG&E Corporation (94) (87) (7) 8 % (187) (172) (15) 9 % Utility $ 827 $ 608 $ 219 36 % $ 1,778 $ 1,300 $ 478 37 % PG&E Corporation’s net loss primarily consists of interest expense on long-term debt. Utility The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2026 and 2025. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact net income. Three Months Ended June 30, Net Change Percentage Change Six Months Ended June 30, Net Change Percentage Change (in millions) 2026 2025 2026 2025 Electric $ 4,388 $ 4,414 $ (26) (1) % $ 9,355 $ 8,549 $ 806 9 % Natural gas 1,514 1,484 30 2 % 3,428 3,332 96 3 % Total operating revenues 5,902 5,898 4 — % 12,783 11,881 902 8 % Cost of electricity 800 599 201 34 % 1,361 998 363 36 % Cost of natural gas 115 111 4 4 % 585 607 (22) (4) % Operating and maintenance 2,537 2,854 (317) (11) % 5,641 5,492 149 3 % Wildfire-related claims, net of recoveries — 50 (50) (100) % — 99 (99) (100) % Wildfire Fund expense 126 109 17 16 % 228 185 43 23 % Depreciation, amortization, and decommissioning 1,062 1,073 (11) (1) % 2,228 2,170 58 3 % Total operating expenses 4,640 4,796 (156) (3) % 10,043 9,551 492 5 % Operating Income 1,262 1,102 160 15 % 2,740 2,330 410 18 % Interest income 107 179 (72) (40) % 223 293 (70) (24) % Interest expense (699) (713) 14 (2) % (1,416) (1,368) (48) 4 % Other income, net 100 83 17 20 % 218 154 64 42 % Income Before Income Taxes 770 651 119 18 % 1,765 1,409 356 25 % Income tax provision (benefit) (61) 39 (100) (256) % (20) 102 (122) (120) % Net Income 831 612 219 36 % 1,785 1,307 478 37 % Preferred stock dividend requirement 4 4 — — % 7 7 — — % Income Available for Common Stock $ 827 $ 608 $ 219 36 % $ 1,778 $ 1,300 $ 478 37 % 13 Operating Revenues The Utility’s electric and natural gas operating revenues increased by $4 million, or 0%, in the three months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to: •$201 million more in revenues to recover the cost of electricity in the three months ended June 30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income. Partially offset by: •approximately $180 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the three months ended June 30, 2026, compared to the same period in 2025. The Utility’s electric and natural gas operating revenues increased by $902 million, or 8%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to: •approximately $620 million in revenues authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the six months ended June 30, 2026, with no comparable revenues in the same period in 2025. The revenues recognized are incremental to revenues previously recognized for interim rate relief; and •$363 million more in revenues to recover the cost of electricity in the six months ended June 30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income. Partially offset by: •approximately $240 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the six months ended June 30, 2026, compared to the same period in 2025. Cost of Electricity The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-invest program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly from third parties. The Cost of electricity increased by $201 million, or 34%, and by $363 million, or 36%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily the result of lower CAISO market sales revenues, lower energy contract sales and higher CAISO transmission costs, partially offset by decreases in natural gas prices and volumes used in Utility owned generation. Cost of Natural Gas The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-invest program and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. There was no material change to the Cost of natural gas in the three months ended June 30, 2026, compared to the same period in 2025. The Cost of natural gas decreased by $22 million, or 4%, in the six months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily the result of lower procurement costs due to lower natural gas prices and volumes, partially offset by an increase in greenhouse gas emission expenses associated with California’s cap-and-invest program. 14 Operating and Maintenance The Utility’s Operating and maintenance expenses decreased by $317 million, or 11%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to approximately $180 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended June 30, 2026, compared to the same period in 2025. The Utility’s Operating and maintenance expenses increased by $149 million, or 3%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to: •approximately $400 million in costs due to recognition of previously deferred expenses authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the six months ended June 30, 2026, with no comparable costs in the same period in 2025. The expenses are incremental to the expenses previously recognized in the 2023 WMCE application as part of interim rate relief. Partially offset by: •approximately $240 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the six months ended June 30, 2026, compared to the same period in 2025. Wildfire-Related Claims, Net of Recoveries The Utility’s Wildfire-related claims, net of recoveries decreased by $50 million, or 100%, and $99 million, or 100%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. The Utility recognized pre-tax charges of $50 million and $100 million related to the 2019 Kincade fire in the three and six months ended June 30, 2025, respectively, with no comparable costs in the same periods in 2026. Wildfire Fund Expense The Utility’s Wildfire Fund expense increased by $17 million, or 16%, and $43 million, or 23%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily due to accelerated amortization associated with SCE’s disclosure of a receivable from the Wildfire Fund related to the Eaton Fire, with no comparable costs in the same periods in 2025. Depreciation, Amortization, and Decommissioning The Utility's Depreciation, amortization, and decommissioning expenses decreased by $11 million, or 1%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to the reversal of accrued decommissioning expenses due to the sale of a gas storage facility. The Utility’s Depreciation, amortization, and decommissioning expenses increased by $58 million, or 3%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to the growth in plant balance from capital additions. Interest Income The Utility’s Interest income decreased by $72 million, or 40%, and $70 million, or 24%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These decreases were primarily due to lower interest-bearing account balances. Interest Expense The Utility’s Interest expense decreased by $14 million, or 2%, in the three months ended June 30, 2026, compared to the same period in 2025. This decrease was primarily due to lower interest on regulatory accounts. The Utility’s Interest expense increased by $48 million, or 4%, in the six months ended June 30, 2026, compared to the same period in 2025. This increase was primarily due to the issuance of additional long-term debt. 15 Other Income, Net The Utility’s Other Income, Net increased by $17 million, or 20%, and $64 million, or 42%, in the three and six months ended June 30, 2026, compared to the same periods in 2025. These increases were primarily due to a higher return from the trust assets for the qualified pension plan in the three and six months ended June 30, 2026, compared to the same periods in 2025. Income Tax Provision The Utility’s Income tax provision decreased by $100 million, or 256%, and $122 million, or 120%, in the three and six months ended June 30, 2026, compared to the same periods in 2025, primarily due to increased deductions for certain costs attributable to electric generation. The effective tax rates were (7.8)% and (1.1)%, and 7.9% and 8.1% for the three and six months ended June 30, 2026 and 2025, respectively. The changes in effective tax rates are primarily due to increased deductions for certain costs attributable to electric generation. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2026 and 2025 primarily due to the effect of the increase in federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. LIQUIDITY AND FINANCIAL RESOURCES Overview PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term. PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. As of June 30, 2026, PG&E Corporation and the Utility had access to approximately $6.5 billion of total liquidity comprised of $256 million of the Utility’s Cash and cash equivalents, $716 million of PG&E Corporation’s (on a standalone basis) Cash and cash equivalents and $5.5 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. Credit Ratings Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s unsecured credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s unsecured credit rating remains below investment grade with one of the major credit rating agencies, the Utility generally does not receive unsecured credit from its energy procurement counterparties, and it may be required to increase its collateral postings if its credit rating is downgraded. 16 Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of June 30, 2026, PG&E Corporation (on a standalone basis) and the Utility had cash and cash equivalents of $716 million and $256 million, respectively. Financial Resources Equity Financings PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect this plan include liquidity and cash flow needs, capital expenditures, interest rates, credit ratings, PG&E Corporation’s common share price, its earnings, the timing and outcome of legislative and ratemaking proceedings, the timing and terms of other financings, and the outcome of the Wildfire-Related Securities Claims. See “Wildfire-Related Securities Litigation” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Debt Financings and Credit Facilities The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements. For more information, see “Credit Facilities” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. DOE Loan Guarantee Agreement As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future. For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K. Other Financings Citizens Energy Corporation On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. On May 7, 2026, the CPUC issued a final decision authorizing the Utility to file an advice letter seeking approval for each entitlements lease. The transactions contemplated by the agreement remain subject to further FERC and CPUC approvals. Dividends PG&E Corporation has announced guidance entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions made by the applicable Board of Directors may be impacted by results of operations, financial condition, cash requirements, contractual restrictions and other factors. 17 For information on dividend declarations and payments, see Note 6 to the Condensed Consolidated Financial Statements in Part I, Item 1. Utility Cash Flows PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the six months ended June 30, 2026 and 2025. The Utility’s cash flows were as follows: Six Months Ended June 30, (in millions) 2026 2025 Net cash provided by operating activities $ 3,639 $ 4,087 Net cash used in investing activities (6,159) (6,268) Net cash provided by financing activities 2,413 1,661 Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents $ (107) $ (520) Operating Activities The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities decreased by $448 million, or 11%, during the six months ended June 30, 2026 as compared to the same period in 2025. This decrease was primarily due to an increase in electric procurement costs driven by lower cash receipts on CAISO-related sales and sales of renewable portfolio standard compliance instruments. Future cash flow from operating activities will be affected by various factors, including: •the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries; •the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1); •the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information); •the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and •the timing and amount of electric and natural gas commodity price volatility and differences between commodity costs and revenue collections. PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Investing Activities The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments. 18 The following table summarizes changes in key components of the Utility’s investing cash flows for the six months ended June 30, 2026, compared to June 30, 2025. (in millions) Six Months Ended June 30, Cash used in investing activities - 2025 $ (6,268) Capital expenditures (623) Net purchases related to customer credit trust investments 755 Net purchases related to self-insurance investment and other investing activities (23) Net decrease in cash used in investing activities 109 Cash used in investing activities - 2026 $ (6,159) Net cash used in investing activities decreased by $109 million, or 2%, during the six months ended June 30, 2026 as compared to the same period in 2025. The decrease was primarily due to a $755 million decrease in net purchases related to customer credit trust investments. The decrease was partially offset by a $623 million increase in capital expenditures, mainly driven by increased investments related to electric distribution customer connections, undergrounding, and distribution maintenance for wildfire risk mitigation. Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will invest $12.4 billion in capital expenditures in 2026. Financing Activities Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation. The following table summarizes changes in key components of the Utility’s financing cash flows for the six months ended June 30, 2026, compared to June 30, 2025. (in millions) Six Months Ended June 30, Cash provided by financing activities - 2025 $ 1,661 Net repayments under credit facilities (630) Net repayments under term loan (860) Proceeds from issuances of long-term debt, net of repayments 1,854 Dividend payments (100) Equity contributions from PG&E Corporation 522 Other financing activities (34) Net increase in cash provided by financing activities 752 Cash provided by financing activities - 2026 $ 2,413 Net cash provided by financing activities increased by $752 million, or 45%, during the six months ended June 30, 2026 as compared to the same period in 2025. The increase was primarily due to: •$1.9 billion increase in proceeds from issuances of long-term debt, net of repayments; and •$522 million increase in equity contributions received from PG&E Corporation. Partially offset by: •$630 million increase in net repayments under credit facilities; •$860 million increase in net repayments under term loan; and •$100 million increase in dividend payments. 19 REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing or outcome of the following proceedings. Key updates to the Utility’s regulatory matters include the following: •In April 2026, the NRC approved the Utility’s 20-year license renewal for extended operations of DCPP; and •In May 2026, the Utility requested interim rate recovery in the 2027 GRC. Cost Recovery Proceedings Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. While the Utility generally expects such unanticipated costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs. In recent years, the Utility has recorded significant amounts to these accounts. Because rate recovery may require CPUC review and authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. If the amount of the costs recorded in these accounts increases, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. For more information, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below. Statuses of the Utility’s cost recovery proceedings are summarized in the following table: Proceeding Request Status 2023 WMCE $2.18 billion of cost recovery Final decision authorizing $1.9 billion of costs issued February 2026. Application for rehearing filed March 2026. 2024 WMCE $596 million of cost recovery Application filed November 2024. A PD is expected by February 2027. 2023 WGSC $2.5 billion of cost recovery Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024. A PD is expected by October 2026. 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. A PD is expected by November 2026. Wildfire Mitigation and Catastrophic Events Cost Recovery Applications 2023 WMCE Application As previously disclosed, on February 5, 2026, the CPUC voted out a final decision in the 2023 WMCE proceeding. On March 16, 2026, the Utility filed an application for rehearing of the final decision with the CPUC. 20 2024 WMCE Application On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in the 2024 WMCE application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023. The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in the CEMA. Opening and reply briefs were filed on May 8 and June 3, 2026, respectively. On June 22, 2026, the CPUC extended the statutory deadline in the proceeding from May 21, 2026 to February 19, 2027. Wildfire and Gas Safety Costs Recovery Application On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs. The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization efforts consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table: (in millions) Recorded Costs Wildfire mitigation plan memorandum account $ 2,095 Fire risk mitigation memorandum account 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 February 26, 2026, the CPUC issued a decision extending the statutory deadline in the proceeding from March 31, 2026 to October 30, 2026. Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA. The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as the Utility continues to resolve claims and draw from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. 21 The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months. Forward-Looking Rate Cases The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases. Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risks associated with the lower level of work achieved compared to that funded by the CPUC. Statuses of the Utility’s forward-looking rate cases are summarized in the following table: Rate Case Request Status 2027 GRC Revenue requirement of $16.64 billion for 2027 Filed May 2025. A PD is expected by March 2027 and a final decision by May 2027. Requested interim rate recovery May 2026. Transmission Owner Rate Case for 2024 (TO21) Revenue requirement of $2.6 billion for 2026 Accepted December 2023, except as to CAISO adder. All other issues resolved August 2025. In February 2026, the U.S. Supreme Court denied petition for certiorari. 2027 General Rate Case On May 7, 2026, the Utility requested interim rate recovery effective January 1, 2027, of 55%, 75%, or 85% of its requested 2027 revenue requirement (approximately $653 million, $891 million, and $1.01 billion, respectively), which has been opposed by some intervenors. Opening briefs were filed on July 2, 2026, and reply briefs will be filed by July 23, 2026. For more information regarding the 2027 GRC, see the 2025 Form 10-K. Transmission Owner Rate Case for 2024 On October 13, 2023, the Utility filed its TO21 rate case with the FERC. On August 5, 2025, the FERC issued a decision approving the settlement that resolved all issues in the proceeding. The decision set a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%. For 2026, the Utility’s annual update includes a revenue requirement of $2.6 billion. On December 29, 2023, the FERC issued an order denying a 0.5% ROE adder. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO, which the FERC denied on June 12, 2024. On June 18, 2024, the Utility and other California IOUs filed an appeal, which the Ninth Circuit Court of Appeals denied on July 11, 2025. After the Ninth Circuit denied a request from the utilities for en banc review on October 7, 2025, they filed a petition for certiorari with the U.S. Supreme Court. On February 23, 2026, the U.S. Supreme Court denied the petition for certiorari. 22 Other Regulatory Proceedings Extension of Diablo Canyon Operations On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On April 2, 2026 the NRC approved the Utility’s 20-year license renewal application for extended operations of DCPP. Continued operation of DCPP beyond October 31, 2029 and October 31, 2030, for Unit 1 and Unit 2, respectively, also requires action by the California Legislature. SB 884 10-Year Distribution Undergrounding Program On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and San Diego Gas & Electric Company (“SDGE”) requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing. On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines. LEGISLATIVE INITIATIVES SB 254 On April 7, 2026, the Wildfire Fund administrator issued its study report pursuant to SB 254. The report sets out policy options for California’s Governor and Legislature to consider. For more information regarding SB 254, see the 2025 Form 10-K. LITIGATION AND OTHER MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and in “Regulatory Matters” above that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. ENVIRONMENTAL MATTERS The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q, as well as Item 1A: “Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. RISK MANAGEMENT ACTIVITIES There have been no material changes to the Utility’s or PG&E Corporation’s risk management activities as previously disclosed in Item 7 of the 2025 Form 10-K. CRITICAL ACCOUNTING ESTIMATES There have been no material changes to the Utility’s or PG&E Corporation’s critical accounting estimates as previously disclosed in Item 7 of the 2025 Form 10-K. 23 ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. 24