PG&E Corp: Form 10-Q for the period ended Sep 30, 2026

OVERVIEW

This is a combined Form 10-Q of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1. It should also be read in conjunction with the 2025 Form 10-K.

Generally, PG&E Corporation’s and the Utility’s revenues vary based on the outcomes of ratemaking proceedings and the amount of pass-through costs incurred. See “Ratemaking Mechanisms” in Part I, Item 1: “Business” in the 2025 Form 10-K regarding how the Utility’s revenues are determined. Factors that cause costs to vary include the cost of purchased power and fuel; the costs of procurement, storage, and transportation of natural gas; weather; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances or changes in interest rates.

The discussions related to the results of operations and liquidity for the three and nine months ended September 30, 2025 compared to the same periods in 2024 are incorporated by reference to Part I, Item 2: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PG&E Corporation’s and the Utility’s combined Form 10-Q for the three and nine months ended September 30, 2025, which was filed with the SEC in October 2025.

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

• The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; California’s wildfire liability framework; 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.

Despite extensive wildfire mitigation measures, the Utility still faces significant wildfire risk, which is exacerbated by climate change, severe weather events, aging infrastructure, and vegetation growth. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is determined primarily by environmental and vegetation conditions, third-party suppression efforts, and the location of the wildfire. The Utility can be liable for these damages and the costs of fire suppression efforts, the Utility’s own assets may be damaged or destroyed, and certain of the Utility’s wildfire mitigation costs are subject to reasonableness review. The extent to which the Utility will be able to recover these costs through rates is uncertain. The Utility will recover its wildfire-related claims in excess of available insurance and legal fees through rates only to the extent that the CPUC or the FERC, as applicable, determines that the Utility has met the applicable prudency standard. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.

The financial impact of past wildfires is significant. PG&E Corporation and the Utility may be able to mitigate the financial impact of 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. For instance, the Utility’s ability to recover wildfire costs above $1.0 billion in a coverage year depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable. With respect to the 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.

With respect to the Wildfire Fund, PG&E Corporation and the Utility expect to re-evaluate the reasonableness of the currently estimated 20-year life and to recognize accelerated amortization of the Wildfire Fund asset based on reliable, publicly available information about the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”). SCE has disclosed probable losses of $1.6 billion and a Wildfire Fund receivable of $645 million for the Eaton fire, which represents the low end of the range of probable losses, and that the remainder of the probable losses are not reasonably estimable. As a result, PG&E Corporation and the Utility could reduce the estimated life to zero and incur up to $3.7 billion of accelerated amortization.

For more information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 regarding the Wildfire Fund asset, Note 3 regarding expenditures incurred for wildfire mitigation, “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 10 regarding wildfire liabilities, “Loss Recoveries” in Note 10 regarding recoveries, and “Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application” in “Regulatory Matters” below.

• The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Regulatory Matters” below.

There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented or if there is a failure to act on wildfire matters, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition. The California Legislature concluded its 2025-2026 legislative session without enacting additional legislation to modify the state's wildfire liability framework. As a result, PG&E Corporation and the Utility could face persistent financial limitations and elevated risk, including challenges obtaining financing on acceptable terms, increased borrowing costs and collateral posting requirements, or increased financing needs, which in turn may negatively impact their financial results and customer affordability.

• Strategic Review and Revised Capital Plan. PG&E Corporation and the Utility announced on September 2, 2026, that they are conducting a strategic review, reducing their planned capital expenditures for 2027 from $13.4 billion to $11.4 billion, and withdrawing the previously disclosed forecast of capital expenditures for 2028 through 2030. The strategic review is evaluating the full range of regulatory, financial, operational and strategic alternatives reasonably available, including the full range of options related to how PG&E Corporation and the Utility are organized and financed to best serve customers and California. Becoming financially strong and securing an investment-grade credit rating is a foundational objective of the review.
• PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above.

Tax Matters

PG&E Corporation’s ability to use its U.S. federal and California state net operating loss carryforwards and certain other tax attributes may be significantly limited if the ownership of PG&E Corporation’s stock by certain shareholders increases beyond statutory thresholds. To reduce the possibility of such a limitation, PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and PG&E Corporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles), in excess of certain thresholds based on the amount and relative value of such stock without approval by the Board of Directors of PG&E Corporation. The computation of the applicable threshold is complex and may vary from date to date; the threshold of the combined value of PG&E Corporation common and mandatory convertible preferred stock was approximately 3.92% as of October 14, 2026. For more information about these restrictions that affect the ownership of PG&E Corporation stock, see “Tax Matters” in Part II, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2025 Form 10-K.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and nine months ended September 30, 2026 and 2025. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of income (loss) attributable to common shareholders for the three and nine months ended September 30, 2026 and 2025:

(in millions)

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, 2026 and 2025. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact net income.

(in millions)

Operating Revenues

The Utility’s electric and natural gas operating revenues decreased by $62 million, or 1%, in the three months ended September 30, 2026, compared to the same period in 2025. This decrease was primarily due to:

• approximately $140 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the three months ended September 30, 2026, compared to the same period in 2025; and
• $111 million less in revenues to recover the cost of electricity in the three months ended September 30, 2026, compared to the same period in 2025. These costs are passed through to customers and do not impact net income.

Partially offset by:

• approximately $60 million in revenue reductions related to the 2022 WMCE proceeding in the three months ended September 30, 2025, with no comparable reductions in the same period in 2026.

The Utility’s electric and natural gas operating revenues increased by $840 million, or 5%, in the nine months ended September 30, 2026, compared to the same period in 2025. This increase was primarily due to:

• approximately $650 million in revenues authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the nine months ended September 30, 2026, with no comparable revenues in the same period in 2025. The revenues recognized are incremental to revenues previously recognized for interim rate relief;
• $252 million more in revenues to recover the cost of electricity in the nine months ended September 30, 2026, compared to the same period in 2025;
• approximately $140 million more in revenues authorized in the 2023 GRC in the nine months ended September 30, 2026, compared to the same period in 2025; and
• approximately $60 million in revenue reductions related to the 2022 WMCE proceeding in the nine months ended September 30, 2025, with no comparable reductions in the same period in 2026.

Partially offset by:

• approximately $380 million less in interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below) in the nine months ended September 30, 2026, compared to the same period in 2025.

Cost of Electricity

The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-invest program, and realized gains and losses on price risk management activities. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly from third parties. These costs are passed through to customers and do not impact net income. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

There were no material changes to the Cost of electricity in the three and nine months ended September 30, 2026, compared to the same periods in 2025.

Cost of Natural Gas

The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-invest program and realized gains and losses on price risk management activities. These costs are passed through to customers and do not impact net income. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

There were no material changes to the Cost of natural gas in the three and nine months ended September 30, 2026, compared to the same periods in 2025.

Operating and Maintenance

The Utility’s Operating and maintenance expenses decreased by $95 million, or 4%, in the three months ended September 30, 2026, compared to the same period in 2025. This decrease was primarily due to:

• approximately $140 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended September 30, 2026, compared to the same period in 2025.

Partially offset by:

• approximately $70 million more in costs associated with extended operations at DCPP in the three months ended September 30, 2026, compared to the same period in 2025.

The Utility’s Operating and maintenance expenses increased by $54 million, or 1%, in the nine months ended September 30, 2026, compared to the same period in 2025. This increase was primarily due to:

• approximately $400 million more in costs due to recognition of previously deferred expenses authorized in the 2023 WMCE final decision (see “2023 WMCE Application” below) in the nine months ended September 30, 2026, with no comparable costs in the same period in 2025. The expenses are incremental to the expenses previously recognized in the 2023 WMCE application as part of interim rate relief; and
• approximately $30 million more in costs associated with extended operations at DCPP in the nine months ended September 30, 2026, compared to the same period in 2025.

Partially offset by:

• approximately $380 million less in previously deferred expenses authorized through interim rate relief for the 2023 WMCE application (see “2023 WMCE Application” below) in the nine months ended September 30, 2026, compared to the same period in 2025.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries decreased by $1 million, or 100%, and $100 million, or 100%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. The Utility recognized pre-tax charges of $100 million related to the 2019 Kincade fire in the nine months ended September 30, 2025, with no comparable costs in the same period in 2026.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense increased by $55 million, or 64%, and $98 million, or 36%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to accelerated amortization associated with SCE’s disclosure of a receivable from the Wildfire Fund related to the Eaton fire, with no comparable costs in the same periods in 2025.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization, and decommissioning expenses increased by $74 million, or 7%, and $132 million, or 4%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to the growth in plant balance from capital additions, partially offset by higher deferred depreciation expense for costs awaiting regulatory decisions.

Interest Income

There was no material change in Interest income in the three months ended September 30, 2026, compared to the same period in 2025.

The Utility’s Interest income decreased by $64 million, or 17%, in the nine months ended September 30, 2026, compared to the same period in 2025. This decrease was primarily due to lower dividend income and lower interest-bearing account balances, partially offset by higher interest-bearing self-insurance related balances.

Interest Expense

The Utility’s Interest expense increased by $38 million, or 5%, and $86 million, or 4%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to the issuance of additional long-term debt and higher borrowings under its revolving credit facility, partially offset by lower balancing account interest.

Other Income, Net

The Utility’s Other Income, Net increased by $19 million, or 20%, and $83 million, or 33%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to a higher return from the trust assets for the qualified pension plan in the three and nine months ended September 30, 2026, compared to the same periods in 2025.

Income Tax Provision

The Utility’s Income tax provision increased by $117 million, or 58%, in the three months ended September 30, 2026, compared to the same period in 2025. This increase was primarily due to decreased deductions for certain costs attributable to electric generation.

The Utility’s Income tax provision decreased by $5 million, or 5%, in the nine months ended September 30, 2026, compared to the same period in 2025. The income tax provision was comparable to the prior-year period.

The effective tax rates were (11.7)% and (4.2)%, and (28.3)% and (4.7)% for the three and nine months ended September 30, 2026 and 2025, respectively. While the effective tax rate for the nine months ended September 30, 2026 was generally consistent compared to the same period in 2025, the change in the effective tax rate for the three months ended September 30, 2026 compared to the same period in 2025 was primarily due to decreased deductions for certain costs attributable to electric generation. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2026 and 2025, primarily due to the effect of the flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term.

PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

As of September 30, 2026, PG&E Corporation and the Utility had access to approximately $5.8 billion of total liquidity comprised of $339 million of the Utility’s Cash and cash equivalents, $563 million of PG&E Corporation’s (on a standalone basis) Cash and cash equivalents and $4.9 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. The Utility also holds restricted cash related to the DOE’s Civil Nuclear Credit Program. As of September 30, 2026, PG&E Corporation (on a standalone basis) and the Utility had Cash and cash equivalents of $563 million and $339 million, respectively.

Financial Resources

Equity Financings

PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect this plan include liquidity and cash flow needs, capital expenditures, interest rates, credit ratings, PG&E Corporation’s common share price, its earnings, the timing and outcome of legislative and ratemaking proceedings, and the timing and terms of other financings.

Debt Financings and Credit Facilities

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

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

DOE Loan Guarantee Agreement

As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future.

For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K.

Other Financings

Citizens Energy Corporation

On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years.

On May 7, 2026, the CPUC issued a final decision authorizing the Utility to file an advice letter seeking approval for each entitlements lease. The transactions contemplated by the agreement remain subject to further FERC and CPUC approvals.

Dividends

PG&E Corporation has announced guidance entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions made by the applicable Board of Directors may be impacted by results of operations, financial condition, cash requirements, contractual restrictions, the strategic review, and other factors.

For information on dividend declarations and payments, see Note 6 to the Condensed Consolidated Financial Statements in Part I, Item 1.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the nine months ended September 30, 2026 and 2025.

The Utility’s cash flows were as follows:

(in millions)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities decreased by $757 million, or 11%, during the nine months ended September 30, 2026 as compared to the same period in 2025. This decrease was primarily due to:

• an increase in electric procurement costs driven by lower sales of renewable portfolio standard compliance instruments into the market and lower CAISO-related revenues; and
• a decrease in collections driven by recoveries related to 2020 to 2023 WMCE rate cases.

Partially offset by:

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

Future cash flow from operating activities will be affected by various factors, including:

• the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;
• the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1);
• the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);
• the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and
• the timing and amount of electric and natural gas commodity price volatility and differences between commodity costs and revenue collections.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

Investing Activities

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments.

The following table summarizes changes in key components of the Utility’s investing cash flows for the nine months ended September 30, 2026, compared to September 30, 2025.

(in millions)

Net cash used in investing activities increased by $46 million, or 0.5%, during the nine months ended September 30, 2026 as compared to the same period in 2025. The increase was primarily due to a $990 million increase in capital expenditures, mainly driven by increased investments in electric transmission and distribution hardening, capacity, reliability, and interconnection work. The increase was partially offset by a $821 million decrease in net purchases related to customer credit trust investments, and by a $123 million decrease in net purchases related to self‑insurance investments.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility forecasts that it will invest $12.4 billion in capital expenditures in 2026 and $11.4 billion in 2027. The strategic review may result in further changes in planned capital expenditures.

Financing Activities

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the strategic review, the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation.

The following table summarizes changes in key components of the Utility’s financing cash flows for the nine months ended September 30, 2026, compared to September 30, 2025.

(in millions)

Net cash provided by financing activities increased by $1.3 billion, or 69%, during the nine months ended September 30, 2026 as compared to the same period in 2025. The increase was primarily due to:

• $2.7 billion increase in proceeds from issuances of long-term debt, net of repayments; and
• $527 million increase in equity contributions received from PG&E Corporation.

Partially offset by:

• $1.5 billion decrease in net borrowings under credit facilities;
• $180 million increase in net repayments under term loan; and
• $149 million increase in dividend payments.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing or outcome of the following proceedings.

Key updates to the Utility’s regulatory matters include the following:

• On August 13, 2026, the CPUC adopted an administrative consent order approving a settlement with the CPUC’s enforcement division for the 2022 Mosquito fire.
• On September 18, 2026, the CPUC issued a PD in Track 1 of the WGSC proceeding that would authorize recovery of approximately $1.8 billion of recorded wildfire mitigation costs for the 2020 to 2022 period and disallow approximately $477 million of requested costs.
• On September 23, 2026, the CPUC issued a PD in the Utility’s 2027 GRC proceeding that would authorize the Utility to recover $456 million in interim rate recovery effective January 1, 2027.
• On September 30, 2026, the Utility filed a ten-year Electrical Undergrounding Plan (“EUP”) for the years 2028 through 2037 with the OEIS.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. While the Utility generally expects such unanticipated costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.

In recent years, the Utility has recorded significant amounts to these accounts. Because rate recovery may require CPUC review and authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs.

If the amount of the costs recorded in these accounts increases, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

For more information, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below.

Statuses of the Utility’s cost recovery proceedings are summarized in the following table:

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2023 WMCE Application

As previously disclosed, on February 5, 2026, the CPUC voted out a final decision in the 2023 WMCE proceeding. On March 16, 2026, the Utility filed an application for rehearing of the final decision with the CPUC, which the CPUC denied on August 14, 2026. On September 14, 2026, the Utility filed a petition for a writ of review with the California Court of Appeal.

2024 WMCE Application

On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in the 2024 WMCE application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023.

The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in the CEMA. Opening and reply briefs were filed on May 8 and June 3, 2026, respectively.

On June 22, 2026, the CPUC extended the statutory deadline in the proceeding from May 21, 2026 to February 19, 2027.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization efforts consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:

(in millions)

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 September 17, 2026, the CPUC extended the statutory deadline in the proceeding to March 31, 2027.

On September 18, 2026, the CPUC issued a PD that would authorize recovery of approximately $1.8 billion of the $2.3 billion of Track 1 costs requested by the Utility, consisting primarily of Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account balances. The PD does not address recovery of amounts recorded in the Gas Storage Balancing Account, In-Line Inspection Memorandum Account, and other memorandum and balancing accounts that are being considered separately in Track 2 of the proceeding. The PD would also disallow approximately $477 million of requested costs, including approximately $291 million of capital expenditures that would be permanently excluded from rate base.

Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA.

The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as a result of payments by the Utility to resolve claims and draws from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risks associated with the lower level of work achieved compared to that funded by the CPUC.

Statuses of the Utility’s forward-looking rate cases are summarized in the following table:

2027 General Rate Case

On May 7, 2026, the Utility requested interim rate recovery effective January 1, 2027, of 55%, 75%, or 85% of its requested 2027 revenue requirement (approximately $654 million, $891 million, and $1.01 billion, respectively), which has been opposed by some intervenors. On September 23, 2026, the CPUC issued a PD that would authorize the Utility to recover $456 million in interim rate recovery effective January 1, 2027. The CPUC could vote on this PD as early as October 29, 2026.

Opening briefs were filed on July 2, 2026, and reply briefs were filed on July 23, 2026.

For more information regarding the 2027 GRC, see the 2025 Form 10-K.

Transmission Owner Rate Case for 2024

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. On August 5, 2025, the FERC issued a decision approving the settlement that resolved all issues in the proceeding. The decision set a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%. For 2026, the Utility’s annual update includes a revenue requirement of $2.6 billion.

On December 29, 2023, the FERC issued an order denying a 0.5% ROE adder. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO, which the FERC denied on June 12, 2024. On June 18, 2024, the Utility and other California IOUs filed an appeal, which the Ninth Circuit Court of Appeals denied on July 11, 2025. After the Ninth Circuit denied a request from the utilities for en banc review on October 7, 2025, they filed a petition for certiorari with the U.S. Supreme Court. On February 23, 2026, the U.S. Supreme Court denied the petition for certiorari.

Other Regulatory Proceedings

Extension of Diablo Canyon Operations

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On April 2, 2026, the NRC approved the Utility’s 20-year license renewal application for extended operations of DCPP. Continued operation of DCPP beyond October 31, 2029 and October 31, 2030, for Unit 1 and Unit 2, respectively, also requires action by the California Legislature.

SB 884 10-Year Distribution Undergrounding Program

On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and San Diego Gas & Electric Company requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing. On October 16, 2026, the CPUC issued a PD in response to the joint application that did not adopt most of the proposals submitted by the Utility, SCE and San Diego Gas & Electric Company. The Utility is currently evaluating the PD.

On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines.

On September 30, 2026, the Utility filed a ten-year Electrical Undergrounding Plan (“EUP”) for the years 2028 through 2037 with the OEIS.

Under the proposed plan, the Utility would install 5,000 miles of electrical distribution conduit underground to mitigate wildfire risk and increase electric reliability by reducing the need to de-energize electric distribution lines during periods of increased wildfire risk. The Utility estimates the cost of the proposed EUP, if fully approved, as $16.6 billion in capital expenditures over the ten-year period.

Pursuant to Public Utilities Code Section 8388.5, the OEIS has nine months to review and approve or deny the plan. Before approving the plan, the OEIS may require the Utility to modify the plan or to modify and resubmit the plan. If OEIS approves the plan, the Utility will file an application within 60 days to recover associated costs from the CPUC, which will have nine months to review and approve or deny the application.

LEGISLATIVE INITIATIVES

SB 254

On April 7, 2026, the Wildfire Fund administrator issued its study report pursuant to SB 254. The report sets out policy options for California’s Governor and Legislature to consider. The California Legislature concluded its 2025-2026 legislative session without enacting additional legislation to modify the state's wildfire liability framework. For more information regarding SB 254, see the 2025 Form 10-K.

LITIGATION AND OTHER MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and in “Regulatory Matters” above that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q, as well as Item 1A: “Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

RISK MANAGEMENT ACTIVITIES

There have been no material changes to the Utility’s or PG&E Corporation’s risk management activities as previously disclosed in Item 7 of the 2025 Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

There have been no material changes to the Utility’s or PG&E Corporation’s critical accounting estimates as previously disclosed in Item 7 of the 2025 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

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

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. See the section above entitled “Risk Management Activities” in Part I, Item 2 and Notes 8 and 9 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

As required by Rules 13a-15(b) or 15d-15(b) under the Exchange Act, management of PG&E Corporation and the Utility carried out an evaluation, under the supervision and with the participation of their respective principal executive officers and principal financial officers, of the effectiveness of the design and operation of their disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. No matter how well designed and operated, disclosure controls and procedures can provide only reasonable, rather than absolute, assurance of achieving the desired control objectives. Based on the foregoing, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers concluded that such controls and procedures were effective as of the end of the period covered by this Form 10-Q.

There were no changes in internal control over financial reporting that occurred during the three months ended September 30, 2026, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see Item 1A: “Risk Factors” in the 2025 Form 10-K, as supplemented in the section of this Form 10-Q entitled “Forward-Looking Statements.”