Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2024 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 2024 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 conditions; criminal, civil and regulatory penalties or charges for wildfires; the outcomes of ratemaking proceedings; and changes 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 nine months ended September 30, 2024 compared to the same periods in 2023 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 months ended September 30, 2024, which was filed with the SEC in November 2024.

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, and system hardening (such as undergrounding). The Utility’s wildfire mitigation efforts have also benefited in recent years from improved ignition response and situational awareness tools like weather stations and risk modeling. These initiatives reduce the Utility’s wildfire risk. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.

PG&E Corporation and the Utility have and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it regularly reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the OEIS based on its ongoing review. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate change (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of September 30, 2025, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.325 billion, $2.125 billion, and $250 million for claims in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses with the exception of amounts relating to the 2019 Kincade fire, which represent the best estimate of the liability, but 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. See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

As of September 30, 2025, the Utility has recorded insurance receivables of $523 million for the 2021 Dixie fire and $256 million for the 2022 Mosquito fire.

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 impacts of AB 1054 and SB 254 on PG&E Corporation and the Utility are subject to numerous, substantial uncertainties, including the Utility’s ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable and therefore not subject to reimbursement by the Utility. The Utility’s ability to recover wildfire costs also 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.

With respect to the Wildfire Fund, Edison International and Southern California Edison Company (together, “SCE”) have 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 Condensed Consolidated Financial Statements in Part I, Item 1). 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 $1.125 billion for the 2021 Dixie fire, of which it had received $609 million as of September 30, 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 all or a portion of expenses that it has recorded as receivables. As of September 30, 2025, the Utility has recorded receivables for regulatory recovery of $626 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. See “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 for more information.

• The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. 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.

• 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 depends on capital market conditions. Increased volatility in capital markets and 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” in the 2024 Form 10-K and “Forward-Looking Statements” above.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $33.7 billion and a California net operating loss carryforward of approximately $34.9 billion as of December 31, 2024.

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. In general, an ownership change occurs if the aggregate value of stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”) contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Accordingly, although PG&E Corporation had 2,675,654,015 common shares outstanding as of October 15, 2025, only 2,197,910,425 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 October 15, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of October 15, 2025 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation.

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 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.

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 nine months ended September 30, 2025 and 2024:

			Three Months Ended September 30,												Nine Months Ended September 30,
(in millions)			2025						2024						2025						2024
Consolidated Total			$	823					$	576					$	1,951					$	1,828
PG&E Corporation			(87)						(39)						(259)						(126)
Utility			$	910					$	615					$	2,210					$	1,954

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.

			Three Months Ended September 30,												Nine Months Ended September 30,
(in millions)			2025						2024						2025						2024
Operating Revenues
Electric			$	4,755					$	4,538					$	13,304					$	13,048
Natural gas			1,495						1,403						4,827						4,740
Total operating revenues			6,250						5,941						18,131						17,788
Operating Expenses
Cost of electricity			1,015						835						2,013						1,919
Cost of natural gas			131						89						738						822
Operating and maintenance			2,636						2,678						8,128						8,062
SB 901 securitization charges, net			35						33						35						33
Wildfire-related claims, net of recoveries			1						74						100						70
Wildfire Fund expense			86						139						271						295
Depreciation, amortization, and decommissioning			1,132						1,059						3,302						3,134
Total operating expenses			5,036						4,907						14,587						14,335
Operating Income			1,214						1,034						3,544						3,453
Interest income			91						153						384						486
Interest expense			(691)						(721)						(2,059)						(2,125)
Other income, net			97						82						251						240
Income Before Income Taxes			711						548						2,120						2,054
Income tax (benefit) expense			(202)						(70)						(100)						90
Net Income			913						618						2,220						1,964
Preferred stock dividend requirement			3						3						10						10
Income Available for Common Stock			$	910					$	615					$	2,210					$	1,954

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.

Partially offset by:

• 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.

Partially offset by:

• 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 the nine 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 the nine 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 the nine 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 the three 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.

Partially offset by:

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

Partially offset by:

• 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 the nine 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 the nine 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 the nine 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 the three 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 the nine 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 the nine months ended September 30, 2025, as compared to pre-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.

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 September 30, 2025, PG&E Corporation and the Utility had access to approximately $6.1 billion of total liquidity comprised of $253 million of the Utility’s Cash and cash equivalents, $151 million of PG&E Corporation’s Cash and cash equivalents, and $5.7 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.

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 September 30, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $151 million and $253 million, respectively.

Self-Insurance

As of September 30, 2025, the Utility had contributed $988 million to Pacific Energy Risk Solutions, LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of September 30, 2025, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, $8 million was classified as Cash and cash equivalents, and $1.0 billion, measured at fair value, was classified as Wildfire self-insurance asset.

As of September 30, 2025, the Utility had contributed $96 million to Pacific Casualty Insurance Company, LLC, its wholly-owned subsidiary and captive insurance company for the administration of non-wildfire liability self-insurance. As of September 30, 2025, $19 million was classified as Restricted cash and cash equivalents due to minimum capital and surplus requirements, an immaterial amount was classified as cash and cash equivalents, and $77 million, measured at fair value, was included in Other current assets.

For more information, see “Self-Insurance” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

Financial Resources

Equity Financings

PG&E Corporation has completed the planned equity financing for its $73 billion capital expenditure plan for 2026 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 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

Debt Financings

Utility

The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.

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 expects to use the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount 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 expects to use the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount 3.15% First Mortgage Bonds due January 1, 2026. The Utility expects to use the remaining net proceeds from the offerings for general corporate purposes.

Credit Facilities and Term Loans

Utility

As of September 30, 2025, PG&E Corporation and the Utility had $650 million and $5.1 billion available under their respective $650 million and $5.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow 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.

On April 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity 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 up of 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.

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.

For more information, see “Credit Facilities and Term Loans” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

Other Financings

DOE Loan Guarantee Agreement

On January 17, 2025, the Utility entered into the following agreements: (1) the DOE Loan Guarantee Agreement; (2) a note purchase agreement dated as of January 17, 2025 (the “Note Purchase Agreement”), among the Utility, the Federal Financing Bank (“FFB”), and the DOE; and (3) a future advance promissory note dated January 17, 2025, made by the Utility to FFB (the “Note” and together with the Note Purchase Agreement, the “FFB Note Documents”).

The FFB Note Documents provide for a multi-advance term loan facility (the “Facility”), under which the Utility may make quarterly term loan borrowings through FFB, subject to satisfaction of certain conditions. Proceeds of the advances under the Facility are to be used by the Utility to reimburse for “Eligible Project Costs” previously incurred and either expended or accrued by the Utility in connection with projects that the DOE has determined to be “Eligible Projects” (each as defined in the DOE Loan Guarantee Agreement). The aggregate amount of advances under the Facility may not exceed $15 billion.

As of the date of this report, the Utility has not borrowed any advances under the Facility. The Utility is not able to predict the timing or amount of any funds it may receive from the Facility in the future as a result of the recent change in the administration.

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.

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

Utility

On each of November 29, 2024, February 20, and May 22, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 18, May 15, and August 15, 2025, to holders of record as of January 31, April 30 and July 31, 2025, respectively. On September 18, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on November 15, 2025, to holders of record as of October 31, 2025.

On each of February 20, May 22, and September 18, 2025, the Board of Directors of the Utility declared common stock dividends of $575 million, which were paid to PG&E Corporation on March 18, May 30, and September 26, 2025, respectively.

PG&E Corporation

On each of November 29, 2024, February 20, May 22, and September 18, 2025, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.025 per share, each declaration totaling $55 million, which were paid on January 15, April 15, July 15, and October 15, 2025, to holders of record as of December 31, 2024, March 31, June 30, and September 30, 2025, respectively.

On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share, totaling $23 million, which was paid on February 27, 2025, to holders of record as of February 14, 2025. On each of February 20 and May 22, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, each declaration totaling $24 million, which were paid on May 29 and August 28, 2025, to holders of record as of May 15 and August 15, 2025, respectively. On September 18, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, payable on December 1, 2025, to holders of record as of November 14, 2025.

Utility Cash Flows

PG&E Corporation’s condensed consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the nine months ended September 30, 2025 and 2024.

The Utility’s cash flows were as follows:

			Nine Months Ended September 30,
(in millions)			2025						2024
Net cash provided by operating activities			$	7,019					$	6,272
Net cash used in investing activities			(9,250)						(8,219)
Net cash provided by financing activities			1,874						2,257
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents			$	(357)					$	310

Operating Activities

Net cash provided by operating activities increased by $0.7 billion, or 12%, during the nine months ended September 30, 2025 as compared to the same period in 2024. This increase was primarily due to:

• an increase in collections driven in part by recoveries related to DCPP extended operations and 2023 WMCE interim rate relief;

• a decrease in non-wildfire related insurance costs;

• a decrease in cost of energy as a result of lower carbon allowance purchases; and

• a decrease in wildfire-related payments, net of recoveries.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base and from cost recovery applications (see “Cost Recovery Proceedings” below for more information).

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 following table summarizes changes in key components of the Utility’s investing cash flows for the nine months ended September 30, 2025, compared to September 30, 2024.

(in millions)			Nine Months Ended September 30,
Cash used in investing activities - 2024			$	(8,219)
Capital expenditures			(1,090)
Net purchases related to customer credit trust investments			(233)
Net purchases related to self-insurance investment and other investing activities			292
Net increase in cash used in investing activities			(1,031)
Cash used in investing activities - 2025			$	(9,250)

Net cash used in investing activities increased by $1.0 billion, or 13%, during the nine months ended September 30, 2025 as compared to the same period in 2024. This increase was primarily due to a $349 million payment for the purchase of the Oakland headquarters, as discussed in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, an increase in investments in undergrounding, and additional distribution poles for the WMP.

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. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur $13.2 billion of capital expenditures in 2025.

Financing Activities

The following table summarizes changes in key components of the Utility’s financing cash flows for the nine months ended September 30, 2025, compared to September 30, 2024.

(in millions)			Nine Months Ended September 30,
Cash provided by financing activities - 2024			$	2,257
Net borrowings under credit facilities			3,249
Net borrowings under term loan			1,350
AB 1054 recovery bonds issuance			(1,409)
Short-term debt issuance			(999)
Repayments of long-term debt			(1,125)
Dividend payments			(276)
Proceeds from DWR loan			(980)
Equity contributions from PG&E Corporation			(413)
Other financing activities			220
Net decrease in cash provided by financing activities			(383)
Cash provided by financing activities - 2025			$	1,874

Net cash provided by financing activities decreased by $383 million, or 17%, during the nine months ended September 30, 2025 as compared to the same period in 2024. The decrease was primarily due to:

• $1.41 billion of proceeds related to the issuance of Series 2024-A senior secured recovery bonds in 2024, with no similar transaction in 2025;

• $1.1 billion increase in repayments related to long-term debt;

• $980 million decrease in proceeds related to the DWR loan; and

• $413 million decrease in equity contributions received from PG&E Corporation.

Partially offset by:

• $3.2 billion increase in net borrowings under credit facilities.

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.

LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation 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” below 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.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the Nuclear Regulatory Commission (“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.

During the quarter ended September 30, 2025 and through the date of this filing, key updates to regulatory matters include the following:

• On August 5, 2025, the FERC issued a final order approving an all-party settlement of the Utility’s transmission owner rate case for 2024 (the “TO21” rate case).

• On August 28, 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 to Establish Energization Timelines.

• On September 26, 2025, the CPUC issued a final decision approving $1.06 billion in cost recovery in the 2022 WMCE proceeding.

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 balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA,VMBA, Wildfire Mitigation Balancing Account (“WMBA”), and Microgrids Memorandum Account (“MGMA”), 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.

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 September 30, 2025, the Utility had recorded an aggregate amount of approximately $2.6 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $0.2 billion was authorized for recovery and accounted for as current, and $2.4 billion was accounted for as long term as of September 30, 2025. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

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.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the nine months ended September 30, 2025 are summarized in the following table:

Proceeding						Request (1)						Status
2021 WMCE						Revenue requirement of approximately $1.47 billion						Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. Decision authorizing $429 million of revenue requirement for the VMBA related costs adopted December 2024. Application for rehearing related to VMBA costs denied September 2025.
2022 WMCE						Revenue requirement of approximately $1.29 billion						Final decision authorizing $1.06 billion of total cost recovery issued September 2025.
2023 WMCE						Revenue requirement of approximately $1.86 billion						Application filed December 2023. Decision authorizing $944 million of interim rate relief adopted September 2024. Partial settlement filed June 2025.
2024 WMCE						Revenue requirement of approximately $435 million						Application filed November 2024.
2023 WGSC						Revenue requirement of approximately $688 million						Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024.

(1) The revenue requirement amounts requested do not include interest.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2021 WMCE Application

On December 27, 2024, the CPUC issued a final decision approving a revenue requirement of $429 million associated with costs recorded to the VMBA. On January 27, 2025, the Utility filed an application for rehearing. On September 18, 2025, the CPUC denied the application for rehearing.

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 consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023.

On December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief.

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 disallows $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.

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. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in the 2023 WMCE 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.

On April 14, 2025, the CPUC issued a PD that would extend the statutory deadline in this matter to December 1, 2025.

On June 2, 2025, the Utility filed an unopposed all-party settlement with intervenors for an additional $461 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA. The settlement agreement did not address the Utility’s revenue requirement request of $833 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

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.

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.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the quarter ended September 30, 2025 are summarized in the following table:

Rate Case						Request						Status
Energization Timelines OIR						Capital cost cap increase of $3.13 billion for 2025 and 2026						Final decision authorizing $2.38 billion increase for 2025 and 2026 cost cap issued August 2025.
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 following CPUC schedule changes in a scoping memo.
2026 Cost of Capital						Increase ROE to 11.30% and cost of debt to 5.04%						Filed March 2025.
Transmission Owner Rate Case for 2024						Revenue requirement of $2.78 billion for 2024						Accepted December 2023, except as to CAISO adder. Appeal of FERC’s order regarding CAISO adder pending at Supreme Court. All other issues resolved August 2025.

Energization Timelines Order Instituting Rulemaking

As previously disclosed, on July 16, 2024, the CPUC issued a final decision approving a memorandum account with interim rate relief for the Utility to recover energization costs incremental to the forecasts of the Utility’s Phase 1 2023 GRC, subject to annual caps and reasonableness review in the 2027 GRC application. The overall expenditure cap was set at $2.26 billion for the period of 2024 to 2026. The decision also permitted the Utility to request revisions to the 2025 and 2026 cap amounts under certain conditions. On October 4, 2024, the Utility filed a motion to increase the 2025 and 2026 cap amounts by an aggregate $3.13 billion.

On August 28, 2025, the CPUC issued a final decision that increases the cost cap for 2025 and 2026 by an aggregate $2.38 billion.

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.

The table below compares the portion of CPUC jurisdictional revenue requirements and weighted-average rate base that are requested in the GRC proceeding 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			17.7						73.4
2029			18.7						79.4
2030			19.9						85.4

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 each year 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. These applications set the cost of capital, ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2026.

In the application, as modified by the Utility’s opening brief, the Utility requests the following cost of capital rates:

						Cost						Weight						Weighted Cost
Return on Common Equity						11.30		%				52.00%						5.88%
Return on Preferred Equity						5.52		%				0.30%						0.02%
Return on Long-term debt						5.04		%				47.70%						2.41%

The application also requests CPUC approval of 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. The scoping memo issued by the CPUC provides for a procedural schedule that would provide a final decision in 2025.

Transmission Owner Rate Cases

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 bank 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 results in a reduction in the revenue requirement in 2024 from the effective rate request of $2.78 billion to $2.55 billion. 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%.

Other Regulatory Proceedings

2023-2025 Wildfire Mitigation Plan

The Utility submitted an updated 2025 WMP on April 2, 2024, as directed by the OEIS. On November 19, 2024, the OEIS issued a final approval of the Utility’s 2025 WMP update. On January 16, 2025, the CPUC ratified the OEIS’s approval.

On December 5, 2024, the Utility filed a change order request to update some of the forecasted work in the WMP for 2025. On February 10, 2025, the OEIS issued a decision approving both initiatives in the change order request.

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.

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 addresses 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. The CPUC is considering revising these guidelines.

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. It became effective on that same day. 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.

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.

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 2024 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 2024 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 2024 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.