Pg&e Corp
Management Discussion synthesis.

Cost of Electricity The Utility's Cost of electricity represents the cost of power and fuel used in the Utility's generating facilities and purchased from third parties to serve customers. Cost of electricity includes fuel supplied to other third-party generating facilities, costs to comply with California's cap-and-trade program, realized gains and losses on price risk management activities (see Note 10 of the Notes to the Consolidated Financial Statements in Item 8), and net power purchases from and sales to the CAISO electricity markets and directly from third parties. The Cost of electricity increased by $348 million in 2025 as compared to 2024. This increase was primarily the result of higher procurement costs, including local RA contract costs, FERC approved transmission owner rate case settlement costs, and higher nuclear fuel amortization, partially offset by increased CAISO market net sales, increased sales of various RPS resources, and lower net costs associated with fuel for utility owned generation and contracted generation.

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 10 of the Notes to the Consolidated Financial Statements in Item 8. The Cost of natural gas decreased by $85 million in 2025 as compared to 2024. This decrease was primarily the result of lower GHG emission volumes, favorable price risk management activity resulting from reduced natural gas market volatility, and a reduction in contracted transport capacity, partially offset by higher natural gas procurement costs attributed to increased prices and demand, along with additional contracted storage capacity.

For information on dividend declarations and payments, see Notes 6 and 7 to the Consolidated Financial Statements in Part II, Item 8. 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 year ended December 31, 2025 and 2024. 59

•a decrease in non-wildfire related insurance costs; and •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 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8); •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

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 SDGE 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.

Asset Retirement Obligations PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and estimated decommissioning dates. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plant. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. At December 31, 2025, the Utility's recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.4 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.

Depreciation, Amortization, and Decommissioning The Utility's Depreciation, amortization, and decommissioning expenses increased by $451 million, or 12%, in 2024 compared to 2023. These increases were primarily due to the growth in plant balance from capital additions and an increase in decommissioning expense due to the reversal of approximately $175 million in accrued nuclear decommissioning expense as a result of the 2021 NDCTP final decision in 2023.

(24.7)%(40.1)% Tax credits(0.7)%(2.2)% Fire Victim Trust (3) - %(80.2)% Other, net 1.2 %1.1 % Effective tax rate(4.0)%(134.8)% (1) Includes the effect of state flow-through ratemaking treatment. (2) Includes 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 TCJA.

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 December 31, 2024, PG&E Corporation and the Utility had Cash and cash equivalents of $235 million and $705 million, respectively. As of December 31, 2024, the Utility had contributed $911 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 December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 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 14 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation On each of February 13, May 16, and September 19, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, each declaration totaling $21 million, which were paid on April 15, July 15, and October 15, 2024, to holders of record as of March 28, June 28 and September 30, 2024, respectively. On November 29, 2024, the Board of Directors of PG&E Corporation declared a new quarterly common stock dividend of $0.025 per share, totaling $55 million, which was paid on January 15, 2025, to holders of record as of December 31, 2024. In December 2024, PG&E Corporation announced a new dividend policy 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 determined by the Board may be impacted by earnings, cash flows, credit metrics and other business conditions. 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, to be payable on March 1, 2025, to holders of record as of February 14, 2025.

Other investing activities17 Net increase in cash used in investing activities(2,213) Cash used in investing activities - 2024$(11,375) 73 Net cash used in investing activities increased by $2.2 billion, or 24%, in 2024 compared to 2023. The increases were primarily due to a $898 million increase in purchases of self-insurance investments in 2024, and a $677 million increase in net purchases of customer credit trust investments, net of proceeds from sales. In addition, capital expenditures increased by $655 million in 2024 compared to 2023 primarily due to increased customer connection energization and electric distribution pole replacement. 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 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $650 million to be contributed by March 2025 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8).

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 proposed decision on the wildfire mitigation costs in the first half of 2025 and a final decision on the gas safety and electric modernization costs by June 2025.

(in millions)Increase(Decrease) inAssumptionIncrease in 2025 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2025

Health care cost trend rate0.50 %$6 $41 Discount rate(0.50)%6 89 Rate of return on plan assets(0.50)%12 - ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $38.3 billion and a California net operating loss carryforward of approximately $34.1 billion as of December 31, 2025. 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 (which could limit PG&E Corporation's or the Utility's ability to use these deferred tax assets to offset taxable income). 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 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 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. 53 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 2,675,711,544 common shares outstanding as of February 4, 2026, only 2,197,967,954 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 February 4, 2026, a person's effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2026 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.

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 20252024 Federal statutory income tax rate21.0 %21.0 %

Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (0.6)%(0.8)% Effect of regulatory treatment of fixed asset differences (2)

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. 57 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. Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2031. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026. As a result, PG&E Corporation expects to pay state income taxes in 2026. See "Tax Matters" above for a discussion of events that could limit PG&E Corporation's ability to use its net operating losses. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in "Purchase Commitments" in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8. As of December 31, 2025, PG&E Corporation and the Utility had access to approximately $4.5 billion of total liquidity comprised of $353 million of the Utility's Cash and cash equivalents, $360 million of PG&E Corporation's Cash and cash equivalents, and $3.8 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.

Restrictive Debt Covenants PG&E Corporation's and the Utility's credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants. One financial covenant requires that the ratio of total consolidated debt to total consolidated capitalization as of the end of each fiscal quarter be no more than 70% for PG&E Corporation and 65% for the Utility. The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. PG&E Corporation's and the Utility's various credit agreements and the DOE Loan Guarantee Agreement contain provisions that may result in an event of default if there was a failure to meet payment terms or observe other covenants under other financing arrangements that could result in an acceleration of payments due. Such provisions are referred to as "cross-default" provisions. As of December 31, 2025, PG&E Corporation and the Utility remain in compliance with all financial covenants.

RESULTS OF OPERATIONS The following discussion presents PG&E Corporation's and the Utility's operating results for 2025 and 2024. See "Key Factors Affecting Financial Results" above for further discussion about factors that could affect future results of operations.

The Utility's cash flows were as follows: Year Ended December 31, (in millions)20252024 Net cash provided by operating activities$9,035 $8,268 Net cash used in investing activities(12,316)(11,375)

Net cash provided by financing activities2,915 3,348 Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents$(366)$241

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. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, 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. 62 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 December 31, 2025, the Utility had recorded an aggregate amount of approximately $2.2 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, and WMBA, substantially all of which was accounted for as long term. See Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8. 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 Consolidated Financial Statements in Part II, Item 8, and "Wildfire Mitigation and Catastrophic Events Cost Recovery Applications" and "Wildfire and Gas Safety Costs Recovery Application" below.

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 14 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 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.

Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2025 and 2024, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $37 million and $6 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

December 31, 2025$1,048 4 $714 December 31, 2024$1,114 4 $708 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity. 69

CRITICAL ACCOUNTING ESTIMATES The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions.

Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations. Refer to "Regulation and Regulated Operations" in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2025, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $22.6 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $24.3 billion. Determining probability requires significant judgment by management and includes consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility's regulatory assets, including utility-retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility's future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting 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 authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. Additionally, SB 901 provides a mechanism for the CPUC to allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold ("CHT"). SB 901 required the CPUC to establish the CHT to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2025, the SB 901 regulatory asset was approximately $5.1 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. 72

Costs Increase in Projected Benefit Obligation at December 31, 2025 Discount rate(0.50)%$13 $1,148 Rate of return on plan assets(0.50)%82 - Rate of increase in compensation0.50 %35 267

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. 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 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 2023 compared to 2022 is incorporated by reference to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC in February 2024.

Cost of Natural Gas The Utility's cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California's cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas decreased by $562 million in 2024 as compared to 2023. These decreases were primarily the result of lower natural gas procurement costs, partially offset by less favorable price risk management results, both of which were due to lower natural gas market prices for the period.

Restrictive Debt Covenants PG&E Corporation's and the Utility's credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants, including a financial covenant requiring PG&E Corporation and the Utility to maintain a total consolidated debt to total consolidated capitalization ratio of no more than 70% and 65% for PG&E Corporation and the Utility, respectively, as of the end of each fiscal quarter. The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. PG&E Corporation's and the Utility's various credit agreements and the DOE Loan Guarantee Agreement contain provisions that may result in an event of default if there was a failure to meet payment terms or observe other covenants under other financing arrangements that could result in an acceleration of payments due. Such provisions are referred to as "cross-default" provisions. As of December 31, 2024, PG&E Corporation and the Utility remain in compliance with all financial covenants. 68

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 December 31, 2024, PG&E Corporation and the Utility had Cash and cash equivalents of $235 million and $705 million, respectively. As of December 31, 2024, the Utility had contributed $911 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 December 31, 2024, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $905 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 14 of the Notes to the Consolidated Financial Statements in Item 8.

Investing Activities The following table summarizes changes in key components of the Utility's investing cash flows for the year ended December 31, 2024, compared to December 31, 2023. (in millions)Year Ended December 31,

ProceedingRequest (1) Status 2021 WMCERevenue requirement of approximately $1.47 billion Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. Decision authorizing $429 million of revenue requirement for the VMBA related costs adopted December 2024.

The Utility will file the next cost of capital application on March 20, 2025 for test year 2026. 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 proposed amount reflects an approximately 11% decrease over the rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see "Transmission Owner Rate Case Revenue Subject to Refund" in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see "Liquidity and Financial Resources - Other Financings" above). The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. 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 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. On December 18, 2024, the settlement judge issued a status report to the FERC stating that the Utility and the other parties have reached a settlement in principle on all issues in the TO21 rate case. The parties will draft an offer of settlement to be filed with the FERC for approval.

Other Regulatory Proceedings 2023-2025 Wildfire Mitigation Plan On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility's wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events. On December 29, 2023, the OEIS issued a final decision approving the Utility's 2023-2025 WMP. On February 15, 2024, the CPUC ratified the OEIS's approval. On January 8, 2024, the Utility filed a change order request to update some of the forecasted work in the WMP for 2024. On May 31, 2024, the OEIS issued a decision approving in part and denying in part the change order request. 80 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.

Health care cost trend rate0.50 %$6 $39 Discount rate(0.50)%6 86 Rate of return on plan assets(0.50)%11 - 90 NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

(40.1)%(49.2)% Tax credits(2.2)%(1.3)% Fire Victim Trust (3) (80.2)%(64.0)% Other, net 1.1 %2.2 % Effective tax rate(134.8)%(118.2)% (1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election. (2) Includes 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 record 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. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA. (3) Includes the tax effect of the Fire Victim Trust's sale of PG&E Corporation common stock. See "Tax Matters" above and Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Ratings PG&E Corporation's and the Utility's credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may 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, 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.

Credit Facilities and Term Loans As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. 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.

SB 884 10-Year Distribution Undergrounding Program On November 9, 2023, the Safety and Policy Division of the CPUC issued a resolution which, if adopted, would establish an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC's review of any large electrical corporation's 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. The draft resolution is currently on the CPUC's March 7, 2024 meeting agenda. On December 13, 2023, the OEIS issued a request for comments as part of its ongoing process to develop guidelines for its program. The Utility and other stakeholders submitted comments on January 8, 2024 and reply comments on January 18, 2024. The Utility anticipates that the OEIS and the CPUC will issue final guidelines in early 2024. The Utility expects to submit its undergrounding plan to the OEIS in mid-2024 before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

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. However, 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 $169 million as of December 31, 2024. See "Wildfire Fund under AB 1054" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 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 December 31, 2024, the Utility has recorded receivables for regulatory recovery of $602 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See "2021 Dixie Fire," and "2022 Mosquito Fire" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information. 62 •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 15 of the Notes to the Consolidated Financial Statements in Item 8, 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 plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to minimize financing costs by identifying and executing on opportunities to efficiently finance the business, which depends on capital market conditions. 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 and "Forward-Looking Statements" above for a list of some of the factors that may cause actual results to differ materially.

Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2024 and 2023, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $6 million and $57 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates. 82

December 31, 2024$1,114 4 $708 December 31, 2023$926 3 $457 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

Contributions to the Wildfire Fund The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California's three large electric IOUs, and (iii) $300 million in annual contributions paid by California's three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a "Wildfire Fund allocation metric" set forth in AB 1054 based on land area in the applicable IOU's service area classified as HFTDs and adjusted to account for risk mitigation efforts. The Utility's Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). 83 On the Emergence Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. In December 2023 and 2024, the Utility made its fifth and sixth annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2024, the Utility has four remaining annual contributions of $193 million (based on the Wildfire Fund allocation metric). PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. As of December 31, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $564 million in Other noncurrent liabilities, $301 million in Current assets - Wildfire Fund asset, and $4.1 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2024 and 2023, the Utility recorded amortization and accretion expense of $383 million and $567 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 20 years is being used to amortize the Wildfire Fund asset. AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Initial use of five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, would have resulted in a six year amortization period. As of December 31, 2024, a 5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by five years assuming greater effectiveness and would decrease the amortization period by five years assuming less effectiveness. Other assumptions used to estimate the useful life include the disclosed cost of wildfires caused by participating electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to "Regulation and Regulated Operations" in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2024, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $23.8 billion. Determining probability requires significant judgment by management and includes consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility's regulatory assets, including utility-retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility's future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting 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 authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. 86 Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold ("CHT"). SB 901 required the CPUC to establish the CHT to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2024, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Costs Increase in Projected Benefit Obligation at December 31, 2024 Discount rate(0.50)%$(1)$1,093 Rate of return on plan assets(0.50)%85 - Rate of increase in compensation0.50 %30 250

(in millions)Increase(Decrease) inAssumptionIncrease in 2024 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2024

SB 901 Securitization Charges, Net The Utility's SB 901 securitization charges, net decreased by $1.23 billion, or 97%, in 2024 compared to 2023. These decreases were due to the recognition of $1.27 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust's sale of PG&E Corporation common stock in 2023, with no comparable activity in 2024. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below.

Wildfire Fund Expense The Utility's Wildfire Fund expense decreased by $184 million, or 32%, in 2024 compared to 2023. These decreases were primarily due to less accelerated amortization of the Wildfire Fund asset and an increase in the estimated period of coverage of the Wildfire Fund from 15 to 20 years. See Note 2 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 66

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 20242023 Federal statutory income tax rate21.0 %21.0 %

Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (0.8)%(34.4)% Effect of regulatory treatment of fixed asset differences (2)

(3) Includes the tax effect of the Fire Victim Trust's sale of PG&E Corporation common stock in 2023. 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. 67 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. The Utility is on track to comply with its authorized regulatory capital structure when the waiver terminates. 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. Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2029. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026. As a result, PG&E Corporation expects to pay state income taxes in 2025 and 2026. See "Tax Matters" above and "Inflation Reduction Act" in Legislative and Regulatory Initiatives below for a discussion of events that could limit PG&E Corporation's ability to use its net operating losses. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in "Purchase Commitments" in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2024, PG&E Corporation and the Utility had access to approximately $6.7 billion of total liquidity comprised of $705 million of the Utility's Cash and cash equivalents, $235 million of PG&E Corporation's Cash and cash equivalents and $5.8 billion of availability under PG&E Corporation's and the Utility's revolving credit facilities.

RESULTS OF OPERATIONS The following discussion presents PG&E Corporation's and the Utility's operating results for 2024 and 2023. See "Key Factors Affecting Financial Results" above for further discussion about factors that could affect future results of operations.

Dividends Utility On each of February 13, May 16, and September 19, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on May 15, August 15, and November 15, 2024, respectively, to holders of record as of April 30, July 31, and October 31, 2024. On November 29, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on February 15, 2025, to holders of record as of January 31, 2025. On each of February 13, May 16, September 19, and November 29, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million, $500 million, $500 million, and $575 million, which were paid to PG&E Corporation on March 25, June 3, September 20, and December 24, 2024. respectively.

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 2024 and 2023.

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 14 of the Notes to the Consolidated Financial Statements in Item 8); •the timing and amount of costs in connection with the 2023-2025 WMP and the portion of the costs previously incurred in connection with the 2020-2022 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 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 15 of the Notes to the Consolidated Financial Statements in Item 8.

Other investing activities17 Net increase in cash used in investing activities(2,213) Cash used in investing activities - 2024$(11,375) 73 Net cash used in investing activities increased by $2.2 billion, or 24%, in 2024 compared to 2023. The increases were primarily due to a $898 million increase in purchases of self-insurance investments in 2024, and a $677 million increase in net purchases of customer credit trust investments, net of proceeds from sales. In addition, capital expenditures increased by $655 million in 2024 compared to 2023 primarily due to increased customer connection energization and electric distribution pole replacement. 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 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $650 million to be contributed by March 2025 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8).

Utility The table below shows the Utility's Consolidated Statements of Income for 2024 and 2023. 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. Year Ended December 31,

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 and outcome of the following proceedings.

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, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and 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 amount of the costs recorded in these accounts has increased. 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 December 31, 2024, the Utility had recorded an aggregate amount of approximately $3.6 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $2.4 billion was accounted for as long term as of December 31, 2024. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. 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 Consolidated Financial Statements in Item 8, 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 year ended December 31, 2024 are summarized in the following table:

2024 WMCERevenue requirement of approximately $435 million Application filed November 2024. 2023 WGSCRevenue requirement of approximately $688 million

Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024. (1) The revenue requirement request amounts do not include interest.

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 proposed decision on the wildfire mitigation costs in the first half of 2025 and a final decision on the gas safety and electric modernization costs by June 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. 78 The Utility's forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2024 are summarized in the following table:

Extension of Diablo Canyon Operations On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at DCPP through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility continues to operate DCPP on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs are responsible for the cost of extended operations. The key steps to continued operations are NRC license renewal and approvals from California state agencies, including the CPUC, CEC, California State Lands Commission, California Coastal Commission, and other state agencies. As set forth below, many of these approvals have been received. On February 28, 2023, and in consultation with the CAISO and CPUC, the CEC determined that it is prudent to extend the operation of DCPP to support electric system reliability through 2030. The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with DCPP. On June 5, 2023, the California State Lands Commission approved an extension of the Utility's lease at DCPP through October 31, 2030.

LEGISLATIVE AND REGULATORY INITIATIVES Inflation Reduction Act In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the AFSI of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility expect to pay corporate alternative minimum tax beginning in 2027, the amount of which may become substantial in future years. As of December 31, 2024, the law did not have a material impact on the PG&E Corporation's and the Utility's Consolidated Financial Statements.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. See "Ratemaking Mechanisms" in Item 1. Description of the Business regarding how the Utility's revenues are determined. 60

Cash, Cash Equivalents, and Restricted Cash 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 that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of December 31, 2023, the Utility had contributed $340 million to its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance, of which approximately $8 million was classified as Restricted cash due to minimum capital and surplus requirements (see "Self-Insurance" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). 69

2023 Cost of Capital Increase ROE to 11% and cost of debt to 4.31% Final decision issued December 2022, adopting a 10% ROE. Intervenor application for rehearing denied in August 2023. Intervenor petition for modification filed December 2023.

Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility's non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving the transfer of FERC-jurisdictional assets from the Utility to Pacific Generation.

Wildfire-Related Liabilities PG&E Corporation and the Utility are subject to potential liabilities related to wildfires. PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. Potential liabilities related to wildfires depend on various factors, including negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys' fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation or the Utility. For example, the Utility's wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages. The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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 11 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas increased in 2022 as compared to 2021 due to increased customer demand and higher market prices. This was driven primarily by below-normal winter temperatures and prolonged drought conditions, resulting in lower California and Pacific Northwest hydro-electric generation output and higher demand from natural-gas fired generation. Lower natural gas storage levels and regional pipeline constraints also contributed to higher natural gas prices.

Update on Ownership Restrictions in PG&E Corporation's Amended Articles As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are 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. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility, and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person's effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of outstanding shares. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

Nuclear Operations Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon's generation to the California electricity market. Management analyzes capacity factors by comparing Diablo Canyon's actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms. Apart from cost-of-service ratemaking and beginning on September 2, 2022, the Utility is entitled to receive a monthly performance-based disbursement. For more information, see "Extension of Diablo Canyon Operations" below. 67 The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility's wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the years ended December 31, 2022 and 2021, Diablo Canyon achieved an average capacity factor of 90% and 84%, respectively. As previously disclosed, Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to excessive vibrations within the main generator. In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to assure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

Financial Resources Equity Financings On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation's common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date for this program, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement. PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See "Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets" below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation's planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

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 2020 Zogg 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 amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see "Wildfire-Related Securities Class Action" in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and "Regulatory Matters" below for more information); •the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility's service area, the ability of the Utility to collect on its customer receivables, the ability of the Utility's customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing; •the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires; •the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see "Regulatory Matters" below for more information); 73 •the timing and amounts of available funds collected for self-insurance (see "2023 General Rate Case" in the Regulatory Matters section of Item 7. Management's Discussion and Analysis for more information); •the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and •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. 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 16 of the Notes to the Consolidated Financial Statements in Item 8.

Financing Activities Net cash provided by financing activities increased by $2.5 billion during 2022 as compared to the same period in 2021. The increase was primarily due to the issuance of $7.5 billion of SB 901 recovery bonds and a decrease of $850 million in net repayments of short-term debt. These increases were partially offset by a $5.9 billion increase in amounts paid to satisfy long-term debt outstanding in 2022 compared to the same period in 2021. 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 future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, 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. During the year ended December 31, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters. •In February 2023, the CPUC approved a final decision, adopting without modification the Utility's settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion. In January 2023, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million. In December 2022, the Utility filed the 2022 WMCE application requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion.

Utility The table below shows certain items from the Utility's Consolidated Statements of Income for 2022 and 2021. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. 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 earnings. 63 Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility's costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

2023 General Rate Case On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC ("the Original Application"). The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In a GRC, the CPUC approves annual revenue requirements for the first year (a "test year") of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as "attrition years"). In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility's revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the Original Application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility's integrated wildfire mitigation strategy, including the Utility's proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility's service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application that revised and superseded the revenue requirement request in the Original Application. On September 6, 2022, the Utility submitted testimony updating the revenue requirement request in its 2023 GRC proceeding. The testimony reflected updates for escalation rates and federal tax law and guidance since the filing of the Original Application. On December 9, 2022, the Utility submitted a post-hearing reply brief. In the reply brief, the Utility updated the revenue requirement request due to the wildfire insurance settlement dated October 7, 2022 discussed below, stipulations with the parties regarding several disputed issues, and a reduction to the Utility's forecast for wildfire system hardening mileage targets over the 2023 to 2026 rate case period. As amended and updated, the Utility's application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. The tables below compare the requested revenue requirements and rate base for the GRC period from 2023 through 2026 to those adopted for 2022 in the 2020 GRC and 2019 GT&S proceedings:

OIR to Revisit Net Energy Metering Tariffs On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers. 86 On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

Electric Asset Inspections The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility's 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility's asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets. On October 26, 2022, the Utility notified the CPUC that the Utility's procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022 and February 1, 2024, the Utility submitted updates to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165's deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Application for Third AB 1054 Securitization Transaction AB 1054 provides that the first $5.0 billion expended in the aggregate by California's three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility's allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the first quarter of 2024, which it subsequently extended through the second quarter of 2024. The $1.38 billion reflected $187 million of recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts approved in the 2023 GRC. These amounts were not included in the first or second securitization transactions. The final amount to be financed using securitization would be based on actual recorded and authorized capital expenditures incurred by the Utility prior to the securitization transaction and not to exceed the remaining $1.38 billion of the Utility's AB 1054 allocation. If approved, the Utility anticipates the transaction will result in the last securitization of AB 1054 capital expenditure amounts subject to the equity rate base exclusion. The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds. The application also requested that the CPUC exclude the securitized debt from the Utility's ratemaking capital structure and adjust the Utility's 2020 GRC, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds. The Utility has requested a financing order to be issued within 180 days after the filing of the application on August 10, 2023. On November 22, 2023, the Utility filed opening briefs to update the capital expenditures forecast for the 2023 GRC final decision and extend the forecast capex period through the second quarter of 2024. On February 15, 2024, the CPUC issued a final decision approving the Utility's application. 83

LEGISLATIVE AND REGULATORY INITIATIVES Inflation Reduction Act In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility continue to evaluate the totality of the law, the regulations issued in connection with it, and its impact on qualifying investments. As of December 31, 2023, the law did not have a material impact on the PG&E Corporation's and the Utility's Consolidated Financial Statements.

Commodity Price Risk The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. The Utility's risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility's natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism. The Utility does not have a balancing account for costs in excess of its revenue requirement for natural gas transportation and storage service to non-core customers. The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders' exposure to these risks. The Utility's value-at-risk was approximately $4 million and $3 million at December 31, 2023 and 2022, respectively. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities.

Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2023 and 2022, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $57 million and $54 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

December 31, 2023$926 3 $457 December 31, 2022$814 1 $162 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity. 85

Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss and they can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See "Loss Recoveries" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to "Regulation and Regulated Operations" in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2023, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.1 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $22.3 billion. 88 Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility's regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility's future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting 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 authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts track costs incurred to implement the CPUC's Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 pandemic. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2023, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Costs Increase in Projected Benefit Obligation at December 31, 2023 Discount rate(0.50)%$2 $1,123 Rate of return on plan assets(0.50)%80 - Rate of increase in compensation0.50 %28 228

(in millions)Increase(Decrease) inAssumptionIncrease in 2023 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2023

Health care cost trend rate0.50 %$6 $39 Discount rate(0.50)%6 86 Rate of return on plan assets(0.50)%11 - 90 NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

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 10 of the Notes to the Consolidated Financial Statements in Item 8. 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 Utility's total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility's own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $32.9 billion and a California net operating loss carryforward of approximately $32.6 billion as of December 31, 2023. 62 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 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 Articles limit Transfers (as defined in the Amended Articles) that increase a person's or entity's (including certain groups of persons) ownership of PG&E Corporation's equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the "Ownership Restrictions"). As discussed below under "Update on Ownership Restrictions in PG&E Corporation's Amended Articles," 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. 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. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. At various dates throughout 2022 and 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2023, the Fire Victim Trust's sale of PG&E Corporation common stock in the aggregate amount of 247,743,590 shares resulted in an aggregate tax benefit of $1.2 billion recorded in PG&E Corporation's and the Utility's Consolidated Financial Statements. Cumulatively through December 31, 2023, the Fire Victim Trust sold all of its 477,743,590 shares resulting in an aggregate tax benefit of approximately $2 billion recorded in PG&E Corporation's and the Utility's Consolidated Financial Statements.

•increased operating cost efficiencies in 2023. SB 901 Securitization Charges, Net The Utility's SB 901 securitization charges, net increased by $659 million, or 108%, in 2023 compared to 2022. These increases were due to the recognition of $1.3 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust's sale of PG&E Corporation common stock in 2023, compared to charges of $608 million in 2022. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below. 66

Wildfire-Related Claims, Net of Recoveries Costs related to wildfires decreased by $173 million, or 73%, in 2023 compared to 2022. The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in 2022. These charges were partially offset by $95 million of probable recoveries through insurance and the WEMA related to the 2022 Mosquito fire and $25 million in probable recoveries through the Wildfire Fund related to the 2021 Dixie fire. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire and $100 million related to the 2019 Kincade fire in 2023. These charges were partially offset by $425 million of probable recoveries through the Wildfire Fund, insurance, and the WEMA related to the 2021 Dixie fire. In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $99 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims. See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 20232022 Federal statutory income tax rate21.0 %21.0 %

Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (34.4)%(26.9)% Effect of regulatory treatment of fixed asset differences (2)

(40.1)%(49.2)% Tax credits(2.2)%(1.3)% Fire Victim Trust (3) (80.2)%(64.0)% Other, net 1.1 %2.2 % Effective tax rate(134.8)%(118.2)% (1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election. (2) Includes 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 record 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. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA. (3) Includes the tax effect of the Fire Victim Trust's sale of PG&E Corporation common stock. See "Tax Matters" above and Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Facilities and Term Loans As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. 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.

RESULTS OF OPERATIONS The following discussion presents PG&E Corporation's and the Utility's operating results for 2023 and 2022. See "Key Factors Affecting Financial Results" above for further discussion about factors that could affect future results of operations.

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 2023 and 2022.

See "Liquidity and Financial Resources" in Item 7 of the 2022 Form 10-K for discussion of the Utility's cash flows for 2022 compared to 2021. The Utility's cash flows were as follows: Year Ended December 31,

See "Results of Operations" in Item 7 of the 2022 Form 10-K for discussion of results of operations for 2022 compared to 2021. 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 net income (loss) available for common shareholders:

Other investing activities(291) Net decrease in cash used in investing activities$907 Cash used in investing activities - 2023$(9,162) Net cash used in investing activities decreased by $907 million, or 9%, in 2023 compared to 2022. The decrease was primarily due to a $1.3 billion decrease in purchases, net of proceeds, related to customer credit trust investments in 2023. This decrease was partially offset by a $145 million intercompany loan repayment in 2022, with no similar transaction in 2023, and a $130 million increase in capital expenditures, primarily due to new customer connections and responses to winter storm events. 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 and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust 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 $10.4 billion of capital expenditures in 2024. 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 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $1.0 billion to be contributed in 2024 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8). 73

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 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 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. 74

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 requests. 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 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, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. 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 amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. 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. 75 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8, and "Wildfire Mitigation and Catastrophic Events Cost Recovery Applications" below. The Utility's cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

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 and the CPUC approve 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 years, 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 risk 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 year ended December 31, 2023 are summarized in the following table:

OIR to Revisit Net Energy Metering Tariffs On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers. 86 On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

Electric Asset Inspections The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility's 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility's asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets. On October 26, 2022, the Utility notified the CPUC that the Utility's procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, accordingly, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165's deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. In addition to its plan to complete the intrusive tests by September 30, 2023, the Utility is performing an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues. The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies. 87

Other Income, Net Changes to Other income, net that impact earnings are primarily driven by fluctuations in the balance of construction work in progress that impact the equity component of AFUDC, and gains and losses on equity securities held by the customer credit trust.

(49.2)%(51.6)% Tax credits(1.3)%(1.2)% Fire Victim Trust (3) (64.0)%91.9 % Other, net 2.2 %2.6 % Effective tax rate(118.2)%86.8 % (1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election. (2) Includes 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 record 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. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act. (3) Includes the tax benefit of the sale of shares by the Fire Victim Trust in 2022 and the tax effect of the grantor trust election for the Fire Victim Trust in 2021. See "Tax Matters" above and Note 7 of the Notes to the Consolidated Financial Statements in Item 8.

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. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. The Utility's total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility's own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity. The cost of electricity decreased in 2022 as compared to 2021. This was primarily due to decreased customer demand and higher energy sales to the CAISO, partially offset by higher fuel prices.

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 11 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas increased in 2022 as compared to 2021 due to increased customer demand and higher market prices. This was driven primarily by below-normal winter temperatures and prolonged drought conditions, resulting in lower California and Pacific Northwest hydro-electric generation output and higher demand from natural-gas fired generation. Lower natural gas storage levels and regional pipeline constraints also contributed to higher natural gas prices.

Cash, Cash Equivalents, and Restricted Cash 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 that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. 69

Financial Resources Equity Financings On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation's common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date for this program, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement. PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See "Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets" below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation's planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

Investing Activities Net cash used in investing activities increased by $3.0 billion during 2022 as compared to the same period in 2021. This increase was primarily driven by a $1.9 billion increase in capital expenditures, including additional system hardening and emergency response work performed in 2022. Additionally, the Utility purchased $1.0 billion of investments as part of the creation of the customer credit trust, with no similar purchases in 2021. 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 and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust 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 that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral 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 between $7.9 billion and $11.2 billion in 2023. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building, and the timing and amount of contributions to the customer credit trust, including shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, 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. During the year ended December 31, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters. •In February 2023, the CPUC approved a final decision, adopting without modification the Utility's settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion. In January 2023, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million. In December 2022, the Utility filed the 2022 WMCE application requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion.

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 requests. 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 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 to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs. In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2022, the Utility had recorded an aggregate amount of approximately $6.2 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Of these costs, approximately $856 million was authorized for recovery and accounted for as current, and $5.3 billion was accounted for as long term as of December 31, 2022. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8. 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. Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to timely recover costs included in these applications. For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8, "Wildfire Mitigation and Catastrophic Events Cost Recovery Applications," and "Catastrophic Event Memorandum Account Application" below. The Utility's cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

2021 WMCE Application On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the "2021 WMCE application"). The costs addressed in this 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 2020. The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility's 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility's proposed revenue requirement would be collected over a two-year period beginning in January 2023. The Utility's requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery request of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of costs, such as employee business travel expenses and in-person training costs, that the Utility was able to avoid due to the pandemic. On January 18, 2023, the Utility, TURN, and Cal Advocates filed a joint motion for approval of a settlement agreement, pursuant to which the Utility would receive a revenue requirement of $720.7 million. The settlement agreement does not address $591.9 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

The Utility has proposed a schedule that would call for a final decision by the CPUC in December 2023. Catastrophic Event Memorandum Account Application The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought to recover CEMA-eligible costs through its WMCE applications. In addition to the Utility's responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to track these costs in the VMBA for the period beginning January 1, 2020.

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 years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on approved revenue requirements and 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 risk associated with the lower level of work achieved compared to that funded by the CPUC. Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications. 78 The Utility's forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility's request for the 50-basis point ROE adder. On March 17, 2020, the FERC issued its order denying requests for rehearing that were previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC's orders in the Ninth Circuit Court of Appeals. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC's order granting the Utility the 50-basis point ROE incentive adder for CAISO participation. The order would extinguish the Utility's refund obligations that might have been required under the TO16 and TO17 rate cases had the Ninth Circuit Court of Appeals not found in the FERC's favor. On May 2, 2022, the CPUC filed a petition for panel rehearing of the order. On May 25, 2022, the Ninth Circuit Court of Appeals issued a decision denying the request for rehearing and the request for a rehearing en banc.

Transmission Owner Rate Case for 2017 (the "TO18" rate case) On July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility's continuing participation in the CAISO. On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility's direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC's revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020. On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (1) impact of the Tax Act on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing. As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of December 31, 2022, the Utility had recorded approximately $258 million to Regulatory assets. 82 On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility's continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in 2022. On April 18, 2022, the Utility sought rehearing of the FERC's determination of the base ROE finding. On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. On May 19, 2022, the FERC denied all parties' rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue. Aside from the ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC's orders in the TO18 proceeding are not expected to result in a material impact on the Utility's financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility's TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See "Transmission Owner Rate Case Revenue Subject to Refund" in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Transmission Owner Rate Case for 2018 (the "TO19" rate case) On July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC's order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation, and so the Utility was not obligated to make a refund to customers based on this matter. See "Transmission Owner Rate Cases for 2015 and 2016" above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC's determination of the base ROE finding.

On December 30, 2020, the FERC approved the settlement without modification. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility's TO20 rate case. Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility's annual updates, and these protests are pending before the FERC. 83

On December 1, 2022, the CPUC issued a resolution authorizing the Utility's exit from the EOEP. Application for Post-Emergence SB 901 Securitization Transaction SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as "securitization"), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. Pursuant to SB 901 and the CPUC's methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers through the creation of a corresponding customer credit trust, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a "securitization" refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds. 84 On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility's 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. and approving a structure for the transaction. As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation's shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC's existing jurisdiction, the decision adopted a transaction structure comprised of four elements: (1) an initial shareholder contribution of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. In addition, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires, which the CPUC subsequently granted on May 11, 2021. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. The financing order authorized the issuance of bonds through the end of 2022. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Application for Second AB 1054 Securitization Transaction AB 1054 provides that the first $5.0 billion expended in the aggregate by California's three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility's allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. Pursuant to an earlier financing order issued by the CPUC authorizing the Utility's initial application for AB 1054 securitization transaction, on November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction. The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.  The application also requested that the CPUC exclude the securitized debt from the Utility's ratemaking capital structure and adjust the Utility's 2020 GRC revenue requirements following the issuance of the recovery bonds. On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million then pending in the 2020 WMCE proceeding.

Integrated Resource Planning Procurement On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision requires incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO's balancing area for the period 2021-2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision requires that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directs the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision. The Utility procured its required RA capacity for the August 1, 2021 milestone from third parties through CPUC-approved contracts for lithium-ion battery energy storage resources with terms ranging from 10-15 years. On December 22, 2020, the Utility filed an advice letter seeking CPUC approval of an additional group of similar contracts that would satisfy the balance of the Utility's procurement obligations for the August 1, 2022 and August 1, 2023 milestones. On April 15, 2021, the CPUC approved the contracts. 90 On June 24, 2021, the CPUC adopted a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirements of Diablo Canyon and once-through-cooling natural gas plants in Southern California by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs subject to the CPUC's integrated resource planning authority. The decision sets procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision sets the Utility's share of the procurement at 2,302 MW of incremental net qualifying capacity. On January 21, 2022, the Utility filed an advice letter with the CPUC seeking approval of a group of nine long-term RA agreements to meet a portion of its procurement requirements under the CPUC's mid-term reliability decision. The agreements are each for a term of 15 years and collectively supply 1,598.7 MW of lithium-ion energy storage capacity with some projects expected to be operational in 2023 and others in 2024.

Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $21.1 billion and California net operating loss carryforward of $18.9 billion at the end of 2021. 66 Under Section 382 of the Internal Revenue Code, 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 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 Articles limit Transfers (as defined in the Amended Articles) that increase a person's or entity's (including certain groups of persons) ownership of PG&E Corporation's equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the "Ownership Restrictions"). As discussed below under "Update on Ownership Restrictions in PG&E Corporation's Amended Articles," due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility and ShareCo. 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 Internal Revenue Code. On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a grantor trust election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the benefits of a grantor trust election, the Utility's tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation's net operating loss has decreased by approximately $10.0 billion which will be offset by payments made by the Fire Victim Trust to the fire victims (which totaled approximately $1.67 billion in 2021) and the net activities of the Fire Victim Trust. Additionally, there was a $1.3 billion charge, net of tax, decreasing net DTAs for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact on PG&E Corporation's and the Utility's Consolidated Financial Statements for the year ended December 31, 2021. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Wildfire Fund Expense Wildfire fund expense that impacted earnings increased by $104 million, or 25%, in 2021 compared to 2020. Due to the Chapter 11 Cases, the Utility's participation in the Wildfire Fund was limited to 40% for the period from July 12, 2019 to June 30, 2020. Additionally, the Utility recorded $43 million of accelerated amortization as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire. Wildfire fund expense that impacted earnings increased by $413 million, or 100%, in 2020 compared to 2019. In 2020, the Utility became eligible to participate in the Wildfire Fund and as a result recorded amortization and accretion expense related to the Wildfire Fund coverage received from the effective date of AB 1054 through December 31, 2020.

See Notes 3 and 14 of the Notes to the Consolidated Financial Statements in Item 8. Depreciation, Amortization, and Decommissioning The Utility's depreciation, amortization, and decommissioning expenses decreased by $66 million, or 2%, in 2021 compared to 2020, primarily due to a reduction in decommissioning expense that was recorded as a result of the final 2018 Nuclear Decommissioning Cost Triennial Proceeding decision. The Utility's depreciation, amortization, and decommissioning expenses increased by $236 million, or 7%, in 2020 compared to 2019, primarily due to capital additions and an increase in depreciation rates associated with the TO20 decision. 70

Interest Income The Utility's interest income that impacted earnings decreased by $17 million, or 44%, in 2021 compared to 2020. Interest income decreased by $43 million, or 52%, in 2020 compared to 2019. The Utility's interest income is primarily affected by changes in regulatory balancing accounts and changes in interest rates.

Interest Expense Interest expense that impacted earnings increased by $262 million, or 24%, in 2021 compared to 2020, primarily due to the issuance of additional long-term debt. The Utility's interest expense that impacted earnings increased by $199 million, or 22%, in 2020 compared to 2019, primarily due to the issuance of new debt in 2020 in connection with the emergence from Chapter 11.

COVID-19 PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility's customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility's customers, the moratorium on service disconnections for residential and small business customers and for eligible medium and large commercial and industrial customers that expired on September 30, 2021, the CPUC's "Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections" and an observed reduction in non-residential electrical load. The Utility's accounts receivable balances over 30 days outstanding as of December 31, 2021, were approximately $1.1 billion, or $832 million higher as compared to the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections for as long as current COVID-19 circumstances persist. 73 On April 16, 2020, the CPUC adopted a resolution ordering utilities to implement a number of emergency customer protections, including a moratorium on service disconnections for residential and small business customers, beginning on March 4, 2020, which it subsequently extended through June 30, 2021. The CPUC authorized utilities to establish memorandum accounts to track incremental costs associated with complying with the resolution. On April 19, 2021, the CPUC issued a final decision to implement a temporary moratorium on service disconnection for medium and large commercial and industrial customers. Although the moratorium on service disconnections ended on September 30, 2021, the Utility does not anticipate resuming service disconnections until 2022. If the moratorium on service disconnections were to be reinstated, it could have a material impact on results of operations, financial condition, and cash flows of PG&E Corporation and the Utility. Although the Utility is seeking further regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance as to the amount or timing of such relief. On July 16, 2021, the California governor signed into law AB 135, which provides financing assistance to customer accounts in arrears. See "Assembly Bill 135" below for more information. AB 135 allocates roughly $300 million in relief funding to the Utility's customers and the amount was paid on January 27, 2022. As of December 31, 2021, PG&E Corporation and the Utility had access to approximately $2.2 billion of total liquidity comprised of approximately $165 million of Utility cash, $126 million of PG&E Corporation cash and $1.9 billion of availability under PG&E Corporation's and the Utility's revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See "Cost of Capital Proceedings" below for more information. The Utility has established the CPPMA memorandum accounts for tracking costs related to the CPUC's emergency authorization and order, which, as of December 31, 2021, totaled $49 million and is reflected in Long-term regulatory assets on the Consolidated Balance Sheets. In addition to the $49 million recorded to the CPPMA that is subject to CPUC approval, the Utility has recorded approximately $127 million of undercollections from residential customers from June 11, 2020 to December 31, 2021 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Consolidated Balance Sheets. During the quarter ended December 31, 2021, there was an adjustment to the RUBA current balancing accounts receivable of $180 million as a result of the expected CAPP funding, which was received on January 27, 2022. For more information on the impact of the COVID-19 pandemic on PG&E Corporation and the Utility, see "PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic" in Item 1A. Risk Factors in Part I of this 2021 Form 10-K. The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

For more information, see "Credit Facilities" in Note 5 of the Notes to the Consolidated Financial Statements in Item 8. Intercompany Note Payable On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The interest rate on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility's Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation's Consolidated Balance Sheet.

202120202019 Revenues and Costs: Revenues and Costs: Revenues and Costs: (in millions)That Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal Utility

Vegetation Management The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC's resolution states that a step 1 triggering event had occurred because the Utility "has made insufficient progress toward approved safety or risk-driven investments related to its electric business." The resolution finds that, based on the CPUC's evaluation of the Utility's EVM work in 2020, the Utility "is not sufficiently prioritizing its Enhanced Vegetation Management ("EVM") based on risk" and "is not making risk-driven investments." The resolution also finds that "less than five percent of the EVM work" the Utility completed in 2020 "was on the 20 highest risk power lines according to [its] own risk rankings." As required by the CPUC's resolution, the Utility submitted a corrective action plan to the CPUC's Executive Director on May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addresses the EVM situation that occurred in 2020 and provides a risk-informed EVM workplan for 2021. The Utility is required to update the information contained in the corrective action plan every 90 days. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. 59

Order Instituting an Investigation into PG&E Corporation's and the Utility's Safety Culture On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the "Safety Culture OII"). The CPUC directed the SED to evaluate the Utility's and PG&E Corporation's organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility's record of operations, including its record of safety incidents. On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility's certificate of convenience and necessity; modifying or eliminating PG&E Corporation's holding company structure; and linking the Utility's rate of return or ROE to safety performance metrics. On September 4, 2020, the administrative law judge issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture and to address any relevant issues that arise, with the CPUC's consultant continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.

Assembly Bill 205 On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs. The Utility received approximately $200 million in November 2022 to reduce the amounts owed by customer accounts in arrears. The amount of funding was determined by the California Department of Community Services and Development, which is the agency responsible for administering the CAPP.

Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2022 and 2021, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $54 million and $76 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates. 90

December 31, 2022$814 1 $162 December 31, 2021$570 1 $63 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

Contributions to the Wildfire Fund The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California's three large electric IOUs, and (iii) $300 million in annual contributions paid by California's three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a "Wildfire Fund allocation metric" set forth in AB 1054 based on land area in the applicable IOU's service area classified as HFTDs and adjusted to account for risk mitigation efforts. The Utility's Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). 91 On the Emergence Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2021 and 2022, the Utility made its third and fourth annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2022, PG&E Corporation and the Utility have six remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in current assets - Wildfire Fund asset, and $4.8 billion in non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset. AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Initial use of five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, would have resulted in a six year amortization period. As of December 31, 2022, a 5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by five years assuming greater effectiveness and would decrease the amortization period by four years assuming less effectiveness. Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by participating electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. Despite the ongoing losses related to wildfires (see Note 15 of the Notes to the Consolidated Financial Statements in Item 8), there is no actual or anticipated change in the cost-of-service regulation of the Utility's operations. Therefore, the Utility continues to apply the accounting ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to "Regulation and Regulated Operations" in Note 3 as well as Note 4 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2022, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $20.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $20.4 billion. Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility's regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility's future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. 94 A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting 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 authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts track costs incurred to implement the CPUC's Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 pandemic. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. For more information, see "Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account" and "Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications" above. Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2022, the SB 901 regulatory asset was approximately $5.4 billion. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Costs Increase in Projected Benefit Obligation at December 31, 2022 Discount rate(0.50)%$5 $1,038 Rate of return on plan assets(0.50)%108 - Rate of increase in compensation0.50 %44 207

(in millions)Increase(Decrease) inAssumptionIncrease in 2022 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2022

Health care cost trend rate0.50 %$8 $38 Discount rate(0.50)%11 81 Rate of return on plan assets(0.50)%15 - NEW ACCOUNTING PRONOUNCEMENTS See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 20222021 Federal statutory income tax rate21.0 %21.0 %

Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (26.9)%24.1 % Effect of regulatory treatment of fixed asset differences (2)

Utility Revenues and Costs that did not Impact Earnings Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs. See below for more information. 66

Update on Ownership Restrictions in PG&E Corporation's Amended Articles As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are 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. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility, and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person's effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of outstanding shares. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

LIQUIDITY AND FINANCIAL RESOURCES Overview PG&E Corporation and the Utility expect to have sufficient liquidity to fund their present and future commitments. The Utility's ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. 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 capital. 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% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility's emergence from Chapter 11. PG&E Corporation's ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility 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. PG&E Corporation's and the Utility's credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may 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. The collateral posting provisions for some of the Utility's power and natural gas commodity, and transportation and service agreements state that if the Utility's credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in "Purchase Commitments" in Note 16 of the Notes to the Consolidated Financial Statements in Item 8. 68

RESULTS OF OPERATIONS The following discussion presents PG&E Corporation's and the Utility's operating results for 2022 and 2021. See "Key Factors Affecting Financial Results" above for further discussion about factors that could affect future results of operations.

AB 1054 Securitization On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The net proceeds were used by the Utility to fund fire risk mitigation capital expenditures that were incurred by the Utility from the period beginning October 2021 through October 2022.

For more information, see "AB 1054" in Note 5 of the Notes to the Consolidated Financial Statements in Item 8. Credit Facilities As of December 31, 2022, PG&E Corporation and the Utility had $500 million and $1.5 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the amendment. 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 from time to time.

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 2020 Zogg 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 amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see "Wildfire-Related Securities Class Action" in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and "Regulatory Matters" below for more information); •the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility's service area, the ability of the Utility to collect on its customer receivables, the ability of the Utility's customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing; •the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires; •the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see "Regulatory Matters" below for more information); 73 •the timing and amounts of available funds collected for self-insurance (see "2023 General Rate Case" in the Regulatory Matters section of Item 7. Management's Discussion and Analysis for more information); •the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and •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. 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 16 of the Notes to the Consolidated Financial Statements in Item 8.

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 Note 2, Note 15, and 16 of the Notes to the Consolidated Financial Statements in Item 8 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. 74

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications 2020 WMCE Application On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the "2020 WMCE application"). The recorded expenditures, which excluded amounts disallowed as a result of the CPUC's decision in the OII into the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the "2017 Northern California wildfires"), and the 2018 Camp fire, consisted of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion. The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and were incremental to those previously authorized in the Utility's 2017 GRC and other proceedings. The majority of costs addressed in this application reflected work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility's requested revenue included amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million. On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

Utility The table below shows certain items from the Utility's Consolidated Statements of Income for 2022 and 2021. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. 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 earnings. 63 Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility's costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

2018 CEMA Application On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million. On April 25, 2019, the CPUC approved the Utility's request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented, commencing on October 1, 2019. On March 17, 2022, the CPUC approved a settlement agreement authorizing the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement will be amortized over a 12-month period, which began on June 1, 2022.

Other Regulatory Proceedings Enhanced Oversight and Enforcement Process In the OII to Consider PG&E Corporation's and the Utility's Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility's operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics. The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC's existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC's regulatory authority, including the authority to issue Orders to Show Cause and OIIs and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC's executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.