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

OVERVIEW

This is a combined Quarterly Report on 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 Item 1. Description of the 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, 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.

The discussion related to the results of operations and liquidity for the three months ended March 31, 2024 compared to the same period in 2023 is 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 Quarterly Report on Form 10-Q for the three months ended March 31, 2024, which was filed with the SEC in April 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, 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 have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned from utility-related ignitions. 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 incurred 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 March 31, 2025, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.275 billion, $1.925 billion, and $100 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.

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, 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 March 31, 2025, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $527 million for the 2021 Dixie fire, and $96 million for the 2022 Mosquito fire. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies.

If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund (see Note 2 and Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1), including as a result of claims made by California’s other participating electric utility companies. For example, victims of wildfires in Southern California in January 2025 have filed lawsuits alleging that Southern California Edison’s equipment was associated with the ignition of such fires. The impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, recoveries for the 2019 Kincade fire would be 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 $925 million for the 2021 Dixie fire, of which it had received $350 million as of March 31, 2025. See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

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 March 31, 2025, the Utility has recorded receivables for regulatory recovery of $609 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 from historical results, see Item 1A: “Risk Factors” in the 2024 Form 10-K and “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.

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 2,675,428,603 common shares outstanding as of April 16, 2025, only 2,197,685,013 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 April 16, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of April 16, 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 months ended March 31, 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 months ended March 31, 2025 and 2024:

			Three Months Ended March 31,
(in millions)			2025						2024
Consolidated Total			$	607					$	732
PG&E Corporation			(85)						(46)
Utility			$	692					$	778

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 months ended March 31, 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 March 31,
(in millions)			2025						2024
Operating Revenues
Electric			$	4,135					$	4,052
Natural gas			1,848						1,809
Total operating revenues			5,983						5,861
Operating Expenses
Cost of electricity			399						321
Cost of natural gas			496						529
Operating and maintenance			2,638						2,631
Wildfire-related claims, net of recoveries			49						(1)
Wildfire Fund expense			76						78
Depreciation, amortization, and decommissioning			1,097						1,022
Total operating expenses			4,755						4,580
Operating Income			1,228						1,281
Interest income			114						134
Interest expense			(655)						(654)
Other income, net			71						79
Income Before Income Taxes			758						840
Income tax provision			63						59
Net Income			695						781
Preferred stock dividend requirement			3						3
Income Available for Common Stock			$	692					$	778

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $122 million, or 2%, in the three months ended March 31, 2025, compared to the same period in 2024. This increase was primarily due to:

• approximately $190 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 March 31, 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 $78 million) in the three months ended March 31, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income;

• approximately $80 million in revenues to recover costs associated with extended operations at DCPP in the three months ended March 31, 2025, as compared to the same period in 2024;

• approximately $45 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the three months ended March 31, 2025, with no comparable revenues in the same period in 2024; and

• approximately $30 million in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in the three months ended March 31, 2025 with no comparable revenues in the same period in 2024.

Partially offset by:

• approximately $275 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended March 31, 2024 with no comparable revenues in the same period in 2025;

• approximately $40 million in lower revenues related to winter storm response in the three months ended March 31, 2025, as compared to the same period in 2024; and

• a decrease in revenues to recover the cost of natural gas (which decreased by approximately $33 million) in the three months ended March 31, 2025, as compared to costs in the same period in 2024. These costs are passed through to customers and do not impact net income.

Cost of Electricity

The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly with third parties. The Cost of electricity increased by $78 million, or 24% in the three months ended March 31, 2025, compared to the same period in 2024. This increase was primarily the result of lower CAISO market sales revenues.

Cost of Natural Gas

The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. The Cost of natural gas decreased by $33 million, or 6%, in the three months ended March 31, 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 purchased for the period.

Operating and Maintenance

The Utility’s Operating and maintenance expenses increased by $7 million, or 0%, in the three months ended March 31, 2025, compared to the same period in 2024. This increase was primarily due to:

• approximately $190 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in the three months ended March 31, 2025, with no comparable costs in the same period in 2024;

• approximately $70 million in costs associated with extended operations at DCPP in the three months ended March 31, 2025, as compared to the same period in 2024;

• approximately $45 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the three months ended March 31, 2025, with no comparable costs in the same period in 2024; and

• approximately $30 million in costs authorized in the GOSMA petition for modification final decision in the three months ended March 31, 2025 with no comparable costs in the same period in 2024.

Partially offset by:

• the recognition of approximately $275 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended March 31, 2024 with no comparable costs in the same period in 2025; and

• approximately $40 million in lower costs related to winter storm response in the three months ended March 31, 2025, as compared to the same period in 2024.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries increased by $50 million, or more than 100%, in the three months ended March 31, 2025, compared to the same period in 2024. The Utility recognized pre-tax charges of $50 million related to the 2019 Kincade fire in the three months ended March 31, 2025, with no comparable costs in the same period in 2024.

Wildfire Fund Expense

There was no material change to Wildfire Fund expense for the periods presented.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization and decommissioning expenses increased by $75 million, or 7%, in the three months ended March 31, 2025, compared to the same period in 2024. This increase was primarily due to the growth in plant balance from capital additions.

Interest Income

The Utility’s Interest income decreased by $20 million, or 15%, in the three months ended March 31, 2025, compared to the same period in 2024. This decrease was primarily due to a decrease in interest rates and interest-bearing account balances in the three months ended March 31, 2025 compared to the same period in 2024.

Interest Expense

There was no material change to Interest expense for the periods presented.

Other Income, Net

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

Income Tax Provision

There was no material change to Income tax provision for the periods presented. The effective tax rates were 8.3% and 7.0 % for the three months ended March 31, 2025 and 2024, respectively. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2025 and 2024 primarily due to the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Cuts and Jobs Act of 2017.

Import Tariffs

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

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. The CPUC has granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025. As of March 31, 2025, the Utility was in compliance with its authorized regulatory capital structure.

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 March 31, 2025, PG&E Corporation and the Utility had access to approximately $8.0 billion of total liquidity comprised of $1.9 billion of the Utility’s Cash and cash equivalents, $163 million of PG&E Corporation’s Cash and cash equivalents, $1.5 billion of availability under the Utility’s Receivables Securitization Program, and $4.5 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s 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 credit rating remains below investment grade with two 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 March 31, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $163 million and $1.9 billion, respectively.

As of March 31, 2025, the Utility had contributed $936 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 March 31, 2025, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $939 million, measured at fair value, was classified as Wildfire self-insurance asset. For more information about wildfire liability self-insurance, 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 $63 billion capital expenditure plan for 2024 through 2028. 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 expects to use the net proceeds of such issuances for (i) the redemption or repayment of all of its $600 million aggregate principal amount of 3.500% First Mortgage Bonds due June 15, 2025, and (ii) the redemption or repayment of all of its $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025. The Utility expects to use the remaining net proceeds from the offerings for general corporate purposes.

Facilities and Term Loans

As of March 31, 2025, PG&E Corporation and the Utility had $500 million and $4.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the $1.5 billion 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 Secured Overnight Financing Rate (“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%.

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 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 January 20, 2025 executive order by President Trump entitled “Unleashing American Energy” regarding funds authorized by the Inflation Reduction Act.

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 approval.

Dividends

Utility

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

On February 20, 2025, the Board of Directors of the Utility declared a common stock dividend of $575 million, which was paid to PG&E Corporation on March 18, 2025.

PG&E Corporation

On November 29, 2024 and February 20, 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, and April 15, 2025, to holders of record as of December 31, 2024 and March 31, 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 February 20, 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 June 1, 2025, to holders of record as of May 15, 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 three months ended March 31, 2025 and 2024.

The Utility’s cash flows were as follows:

			Three Months Ended March 31,
(in millions)			2025						2024
Net cash provided by operating activities			$	2,955					$	2,309
Net cash used in investing activities			(3,264)						(2,930)
Net cash provided by financing activities			1,575						769
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents			$	1,266					$	148

Operating Activities

Net cash provided by operating activities increased by $646 million, or 28%, during the three months ended March 31, 2025 as compared to the same period in 2024. This increase was primarily due to:

• an increase in collections driven in part by the DCPP extended operations recovery and 2023 WMCE interim rate relief;

• an increase in Wildfire Fund-related recoveries; and

• a decrease in benefits related payments.

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 under AB 1054” 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 three months ended March 31, 2025, compared to March 31, 2024.

(in millions)			Three Months Ended March 31,
Cash used in investing activities - 2024			$	(2,930)
Net purchases related to customer credit trust investments			(301)
Other investing activities			(33)
Net increase in cash used in investing activities			(334)
Cash used in investing activities - 2025			$	(3,264)

Net cash used in investing activities increased by $334 million, or 11%, during the three months ended March 31, 2025 as compared to the same period in 2024. This increase was primarily due to a $301 million increase in net purchases of customer credit trust investments, net of proceeds from sales.

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 $12.9 billion of capital expenditures in 2025. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the self-insurance captive (see “Self-Insurance” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1).

Financing Activities

The following table summarizes changes in key components of the Utility’s financing cash flows for the three months ended March 31, 2025, compared to March 31, 2024.

(in millions)			Three Months Ended March 31,
Cash provided by financing activities - 2024			$	769
Net repayments under credit facilities			1,154
Issuance of long-term debt			(524)
Repayments of long-term debt			450
Dividend payments			(125)
Other financing activities			(149)
Net increase in cash provided by financing activities			806
Cash provided by financing activities - 2025			$	1,575

Net cash provided by financing activities increased by $806 million, or 105%, during the three months ended March 31, 2025 as compared to the same period in 2024. The increase was primarily due to:

• $1.2 billion decrease in net repayments under credit facilities; and

• $450 million decrease in repayments related to long-term debt.

Partially offset by:

• $524 million decrease in proceeds related to issuance of long-term debt; and

• $232 million decrease in proceeds related to the DWR loan.

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 March 31, 2025 and through the date of this filing, key updates to regulatory matters include the following:

• On April 4, the Utility submitted its 2026-2028 WMP to the OEIS.

• On March 20, the Utility submitted its 2026 Cost of Capital application to the CPUC.

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, Fire Hazard Prevention Memorandum Account (“FHPMA”), FRMMA, WMPMA, Vegetation Management Balancing Account (“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 March 31, 2025, the Utility had recorded an aggregate amount of approximately $3.4 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $1.1 billion was authorized for recovery and accounted for as current, and $2.3 billion was accounted for as long term as of March 31, 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 continues to increase, 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 three months ended March 31, 2025 are summarized in the following table:

Proceeding						Request (1)						Status
2022 WMCE						Revenue requirement of approximately $1.29 billion						Filed December 2022. Decision authorizing $1.1 billion of interim rate relief adopted June 2023. Partial settlement filed December 2023.
2023 WMCE						Revenue requirement of approximately $1.86 billion						Application filed December 2023. Decision authorizing $944 million of interim rate relief adopted September 2024.
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

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. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision for such requested rate relief. Cost recovery requested in the 2022 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. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

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. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.

On December 19, 2024, the CPUC extended the statutory deadline to resolve the remaining issues in the proceeding to September 30, 2025.

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 proposed decision (“PD”) that would extend the statutory deadline in this matter to December 1, 2025.

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.

The administrative law judge has adopted a schedule that would result in a PD on the wildfire mitigation costs in the first half of 2025.

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. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS approves guidelines. See “SB 884 10-Year Distribution Undergrounding Program” below.

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 March 31, 2025 are summarized in the following table:

Rate Case						Request						Status
2026 Cost of Capital						Increase ROE to 11.30% and cost of debt to 5.05%						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 filed June 2024 and remains pending. All other issues settled March 2025.

Cost of Capital Proceedings

2026 Cost of Capital Application

On March 20, 2025, the Utility (along with the other investor-owned utilities 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, 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						5.05		%				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 Utility, along with the other investor-owned utilities in California, has proposed a procedural schedule that would provide a final decision in 2025.

Transmission Owner Rate Cases

Transmission Owner Rate Case for 2024 (the “TO21” rate case)

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. The utilities’ joint opening brief was filed on September 11, 2024 and reply brief was filed on December 17, 2024. Oral argument is scheduled for June 4, 2025.

On March 21, 2025, the Utility filed with the FERC a settlement in the TO21 rate case. The settlement would resolve 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 settlement would set a base ROE of 10.38%, which does not address the 0.5% ROE adder for participation in the CAISO. The settlement would set 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 its 2026-2028 WMP to the OEIS. 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.

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

The Utility expects to submit its undergrounding plan to the OEIS in late 2025, before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

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 Quarterly Report on 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 and PG&E Corporation’s risk management activities during the three months ended March 31, 2025. These activities are discussed in detail in Item 7 of the 2024 Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

There have been no material changes to the Utility’s and PG&E Corporation’s critical accounting policies during the three months ended March 31, 2025. These accounting estimates and their key characteristics are discussed in detail 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.