PACIFIC GAS & ELECTRIC Co

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and nine months ended September 30, 2025 and 2024. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of income (loss) attributable to common shareholders for the three and nine months ended September 30, 2025 and 2024:

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 nine months ended September 30, 2025 and 2024. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact net income.

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $309 million, or 5%, in the three months ended September 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately $150 million in revenues to recover costs associated with extended operations at DCPP in the three months ended September 30, 2025, with no comparable revenues in the same period in 2024;

•approximately $140 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in the three months ended September 30, 2025, with no comparable revenues in the same period in 2024;

•an increase in revenues to recover the cost of electricity procurement (which increased by approximately $180 million) in the three months ended September 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income; and

•an increase in revenues to recover the cost of natural gas (which increased by approximately $42 million) in the three months ended September 30, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income.

•approximately $100 million in lower interim rate relief as authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the three months ended September 30, 2025, compared with the same period in 2024; and

•an approximately $60 million decrease in revenue due to expense disallowances as per the 2022 WMCE final decision (see “2022 WMCE Application” below) in the three months ended September 30, 2025 with no comparable decrease in the same period in 2024.

The Utility’s electric and natural gas operating revenues increased by $343 million, or 2%, in the nine months ended September 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately $520 million in revenues to recover costs associated with extended operations at DCPP in the nine months ended September 30, 2025, with no comparable revenues in the same period in 2024;

•approximately $490 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in the nine months ended September 30, 2025, with no comparable revenues in the same period in 2024;

•an increase in revenues to recover the cost of electricity procurement (which increased by approximately $94 million) in the nine months ended September 30, 2025, compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income; and

•approximately $50 million in revenues authorized in the GOSMA petition for modification final decision in the nine months ended September 30, 2025, with no comparable revenues in the same period in 2024.

•approximately $540 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the nine months ended September 30, 2024, with no comparable revenues in the same period in 2025;

•approximately $130 million in lower interim rate relief as authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the nine months ended September 30, 2025, compared with the same period in 2024;

•a decrease in revenues to recover the cost of natural gas (which decreased by approximately $84 million) in the nine months ended September 30, 2025, compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income;

•approximately $60 million in lower revenues related to winter storm response in the nine months ended September 30, 2025, compared to the same period in 2024; and

•an approximately $60 million decrease in revenue due to expense disallowances as per the 2022 WMCE final decision (see “2022 WMCE Application” below) in the nine months ended September 30, 2025, with no comparable decrease in the same period in 2024.

Cost of Electricity

The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly from third parties.

The Cost of electricity increased by $180 million, or 22%, in the three months ended September 30, 2025, compared to the same period in 2024. This increase was primarily the result of higher procurement costs and lower renewable energy credit sales in the three months ended September 30, 2025, compared with the same period in 2024.

The Cost of electricity increased by $94 million, or 5%, in thenine months ended September 30, 2025, compared to the same period in 2024. This increase was primarily the result of higher procurement costs and higher nuclear fuel amortization, partially offset by increased renewable energy credit sales in thenine months ended September 30, 2025, compared to the same period in 2024.

Cost of Natural Gas

The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

The Cost of natural gas increased by $42 million, or 47%, in the three months ended September 30, 2025, compared to the same period in 2024. This increase was primarily the result of an increase in GHG emissions expenses, increases in natural gas prices and volumes, and increases in gas storage contract expenses, compared to the same period in 2024.

The Cost of natural gas decreased by $84 million, or 10%, in thenine months ended September 30, 2025, compared to the same period in 2024. This decrease was primarily the result of a reduction in GHG emissions expenses and favorable price risk management results, partially offset by increases in natural gas prices and volumes, compared to the same period in 2024.

Operating and Maintenance

The Utility’s Operating and maintenance expenses decreased by $42 million, or 2%, in the three months ended September 30, 2025, compared to the same period in 2024. This decrease was primarily due to:

•approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to record these as operating expenses, resulting in an increase in operating expense in thethree months ended September 30, 2024, with no comparable costs in the same period in 2025;

•approximately $100 million in lower interim rate relief as authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the three months ended September 30, 2025, compared with the same period in 2024; and

•an approximately $30 million reduction in insurance costs related to the Utility’s adoption of non-wildfire-related self-insurance in the three months ended September 30, 2025, compared with the same period in 2024.

•approximately$130 million in costs associated with extended operations at DCPP in the three months ended September 30, 2025, with no comparable costs in the same period in 2024;

•approximately$140 million in previously deferred expenses authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended September 30, 2025, with no comparable costs in the same period in 2024;

•approximately $40 million increase due to recognition of previously deferred expenses authorized as per the 2022 WMCE final decision (see “2022 WMCE Application” below) in the three months ended September 30, 2025, with no comparable costs in the same period in 2024; and

•an approximately $40 million increase in electric transmission expenses in the three months ended September 30, 2025, compared to the same period in 2024.

The Utility’s Operating and maintenance expenses increased by $66 million, or 1%, in the nine months ended September 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately $490 million in previously deferred expenses authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the nine months ended September 30, 2025, with no comparable costs in the same period in 2024;

•approximately $470 million in costs associated with extended operations at DCPP in the nine months ended September 30, 2025, with no comparable costs in the same period in 2024;

•approximately $80 million increase in electric transmission expenses in thenine months ended September 30, 2025, compared to the same period in 2024; and

•approximately $40 million increase due to recognition of previously deferred expenses as per the 2022 WMCE final decision (see “2022 WMCE Application” below) in thenine months ended September 30, 2025, with no comparable costs in the same period in 2024.

•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 the nine months ended September 30, 2024, with no comparable costs in the same period in 2025;

•approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to record these as operating expense, resulting in an increase in operating expense in thenine months ended September 30, 2024, with no comparable costs in the same period in 2025;

•approximately $130 million in lower interim rate relief as authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in thenine months ended September 30, 2025, compared with the same period in 2024;

•approximately $60 million in lower costs related to winter storm response in the nine months ended September 30, 2025, compared to the same period in 2024; and

•approximately $40 million reduction in insurance costs related to the Utility’s adoption of non-wildfire-related self-insurance in thenine months ended September 30, 2025, compared with the same period in 2024.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries decreased by $73 million, or 99%, in the three months ended September 30, 2025, compared to the same period in 2024. The Utility recognized pre-tax charges of $75 million related to the 2019 Kincade fire in thethree months ended September 30, 2024, with no comparable costs in the same period in 2025.

The Utility’s Wildfire-related claims, net of recoveries increased by $30 million, or 43%, in thenine months ended September 30, 2025, compared to the same period in 2024. The Utility recognized pre-tax charges of $100 million related to the 2019 Kincade fire in thenine months ended September 30, 2025, as compared topre-tax charges of $75 million related to the 2019 Kincade fire in the same period in 2024.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense decreased by $53 million, or 38%, and $24 million, or 8%, in the three and nine months ended September 30, 2025, compared to the same periods in 2024. These decreases were due to lower accelerated amortization

associated with the Wildfire Fund receivable for the 2021 Dixie fire in the three and nine months ended September 30, 2025, compared to the same periods in 2024.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization and decommissioning expenses increased by $73 million, or 7%, and $168 million, or 5%, in the three and nine months ended September 30, 2025, compared to the same periods in 2024. These increases were primarily due to the growth in plant balance from capital additions, partially offset by an increase in deferred depreciation expense for costs pending regulatory approval.

Interest Income

The Utility’s Interest income decreased by $62 million, or 41%, and $102 million, or 21%, in the three and nine months ended September 30, 2025, compared to the same periods in 2024. These decreases were primarily due to a decrease in interest rates and interest-bearing account balances in the three and nine months ended September 30, 2025 compared to the same periods in 2024.

Interest Expense

The Utility’s Interest expense decreased by $30 million, or 4%, and $66 million, or 3%, in the three and nine months ended September 30, 2025, compared to the same periods in 2024. These decreases were primarily due to a decrease in short-term debt with higher, variable interest rates, partially offset by an increase in long-term debt.

Other Income, Net

There was no material change to Other income, net for the periods presented.

Income Tax Provision

The Utility’s Income tax provision decreased by $132 million, or 189%, and $190 million, or 211%, in the three and nine months ended September 30, 2025, compared to the same periods in 2024, primarily due to an increased tax repairs deduction and an additional deduction for certain costs attributable to electric generation.

The effective tax rates were (28.3)% and (4.7)%, and (12.8)% and 4.4%, for the three and nine months ended September 30, 2025 and 2024, respectively. The change in effective tax rate is primarily due to an estimated tax benefit related to an increase in repairs deduction and an additional deduction for certain costs attributable to electric generation. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2025 and 2024 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. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Cuts and Jobs Act of 2017.

Import Tariffs

Changes to import tariffs have not had and are not expected to have a material impact on either PG&E Corporation’s or the Utility’s results of operations. PG&E Corporation and the Utility will continue monitoring and assessing the impacts of changes to import tariffs and will continue working to mitigate related cost increases.