PG&E Corp

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and six months ended June 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 six months ended June 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 six months ended June 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 decreased by $88 million, or 1%, in the three months ended June 30, 2025, compared to the same period in 2024. This decrease was primarily due to:

•approximately $275 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in thethree months ended June 30, 2024, with no comparable revenues in the same period in 2025;

•an approximately $50 million reduction in revenues related to self-insurance (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K) in the three months ended June 30, 2025, as compared to the same period in 2024;

•a decrease in revenues to recover the cost of natural gas (which decreased by approximately $90 million) in thethree months ended June 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

•a decrease in revenues to recover the cost of electricity procurement (which decreased by approximately $160 million) in the three months ended June 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$240 million in revenues to recover costs associated with extended operations at DCPP in the three months ended June 30, 2025, with no comparable revenues in the same period in 2024;

•approximately $190 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in thethree months ended June 30, 2025, with no comparable revenues in the same period in 2024;

•an approximately $80 million increase in the FERC TO formula rate revenue in thethree months ended June 30, 2025, compared to the same period in 2024; and

•approximately$20 million in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in the three months ended June 30, 2025, with no comparable revenues in the same period in 2024.

The Utility’s electric and natural gas operating revenues increased by $34 million, or 0%, in the six months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately$370 million in revenues to recover costs associated with extended operations at DCPP in the six months ended June 30, 2025, with no comparable revenues in the same period in 2024;

•approximately $360 million in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 Wildfire Mitigation and Catastrophic Events Application” below) in the six months ended June 30, 2025, with no comparable revenues in the same period in 2024;

•an approximately $150 million increase in the FERC TO formula rate revenue in thesix months ended June 30, 2025, compared to the same period in 2024; and

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

•approximately $550 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in thesix months ended June 30, 2024, with no comparable revenues in the same period in 2025;

•an approximately $100 million reduction in revenues related to self-insurance (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K) in the six months ended June 30, 2025, as compared to the same period in 2024;

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

•a decrease in revenues to recover the cost of natural gas (which decreased by approximately $130 million) in the six months ended June 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

•a decrease in revenues to recover the cost of electricity procurement (which decreased by approximately $90 million) in the six months ended June 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.

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 with third parties.

The Cost of electricity decreased by $164 million, or 21% in the three months ended June 30, 2025, and by $86 million, or 8% in thesix months ended June 30, 2025, compared to the same periods in 2024. These decreases were primarily the result of lower procurement costs, partially offset by higher nuclear fuel amortization in the three andsix months ended June 30, 2025, compared to the same periods 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 decreased by $93 million, or 46%, in the three months ended June 30, 2025, and by $126 million, or 17%, in thesix months ended June 30, 2025, compared to the same periods in 2024. These decreases were primarily the result of a reduction in GHG emissions expenses and favorable price risk management results, due to less natural gas market price volatility experienced for the present periods, partially offset by increases in natural gas prices and volumes purchased for the present periods, compared to the same periods in 2024.

Operating and Maintenance

The Utility’s Operating and maintenance expenses increased by $101 million, or 4%, in the three months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately$220 million in costs associated with extended operations at DCPP in the three months ended June 30, 2025, with no comparable costs in the same period in 2024; and

•approximately$190 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended June 30, 2025, with no comparable costs in the same period in 2024.

•the recognition of approximately $275 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended June 30, 2024, with no comparable costs in the same period in 2025; and

•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the three months ended June 30, 2024, with no comparable costs in the same period in 2025. For more information, see “Regulatory Matters” below.

The Utility’s Operating and maintenance expenses increased by $108 million, or 2%, in the six months ended June 30, 2025, compared to the same period in 2024. This increase was primarily due to:

•approximately $360 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the six months ended June 30, 2025, with no comparable costs in the same period in 2024; and

•approximately $340 million in costs associated with extended operations at DCPP in the six months ended June 30, 2025, with no comparable costs in the same period in 2024.

•approximately $550 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the six months ended June 30, 2024, with no comparable costs in 2025;

•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the six months ended June 30, 2024, with no comparable costs in the same period in 2025. For more information, see “Regulatory Matters” below; and

•approximately $60 million in lower costs related to winter storm response in the six months ended June 30, 2025, as compared to the same period in 2024.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries increased by $53 million, or more than 100%, and $103 million, or more than 100%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. 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 2024.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense increased by $31 million, or 40%, and $29 million, or 19%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. These increases were primarily due to accelerated amortization associated with an increase in the Wildfire Fund receivable for the 2021 Dixie fire.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization and decommissioning expenses increased by $20 million, or 2%, and $95 million, or 5%, in the three and six months ended June 30, 2025, compared to the same periods in 2024. These increases were primarily due to the growth in plant balance from capital additions.

Interest Income

The Utility’s Interest income decreased by $20 million, or 10%, and $40 million, or 12%, in the three and six months ended June 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 six months ended June 30, 2025 compared to the same periods in 2024.

Interest Expense

The Utility’s Interest expense decreased by $37 million, or 5%, and $36 million, or 3%, in the three and six months ended June 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 $62 million, or 61%, and $58 million, or 36%, in the three and six months ended June 30, 2025, compared to the same periods in 2024, primarily due to higher tax repairs deduction in the three and six months ended June 30, 2025, compared to the same periods in 2024.

The effective tax rates were 7.9% and 8.1%, and 15.2% and 10.6%, for the three and six months ended June 30, 2025 and 2024, respectively. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2025 and 2024 primarily due to 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. 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

PG&E Corporation and the Utility are assessing the impacts of changes to import tariffs, which could increase the costs they pay for goods and services, and their ability to mitigate such cost increases, including through operational, contractual, or regulatory initiatives.