Pg&e Corp,
Fiscal Year 2024.

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

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

(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.

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.

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.

The Utility may not effectively implement its wildfire mitigation initiatives. The Utility's infrastructure is aging and poses risks to safety and system reliability. The Utility's wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. The CPUC will assess penalties on the Utility if there is a finding that the Utility has failed to substantially comply with its WMPs. Wildfires can occur even when the Utility follows its procedures. For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event or where EPSS has been implemented on Utility equipment. The Utility's inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If the Utility's wildfire mitigation initiatives are not effective, a wildfire could be ignited and spread. In addition, on a risk-informed basis, the Utility is making efforts to reduce the frequency and impacts of PSPS. The Utility may be subject to mandated changes to, or restrictions on, its operational practices, regulatory fines and penalties, claims for damages, and reputational harm if the Utility does not execute PSPS in compliance with applicable rules and regulations. The Utility establishes the criteria under which it implements PSPS in its territory. To the extent the Utility's criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility's regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions. PG&E Corporation and the Utility cannot predict the timing and outcome of the various proceedings and litigation in connection with its wildfire mitigation initiatives. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility's implementation of its wildfire mitigation initiatives, which could result in fines, penalties, customer rebates, other payments, or the Utility's failure to obtain cost recovery for amounts expended on these initiatives. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other wildfire mitigation initiatives or liability for damages) could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS and EPSS programs have had an adverse impact on PG&E Corporation's and the Utility's reputation with customers, regulators and policymakers and future PSPS events and EPSS outages may increase these negative perceptions. For more information, see "Regulatory Matters" in Item 7. MD&A.

Privacy In June 2018, the State of California enacted the California Consumer Privacy Act of 2018 (the "CCPA"), which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that created the California Privacy Rights Act (the "CPRA"), which amended and expanded the CCPA. The State of California enacted the CPRA in November 2020, with most provisions operative as of January 1, 2023 and applicable to personal information collected beginning January 1, 2022. Final CPRA regulations are in development. Failure to comply with the CCPA and the CPRA could result in litigation, audits, and the imposition of material fines on PG&E Corporation and the Utility. Additionally, PG&E Corporation and the Utility collect and retain certain personal information of their customers, shareholders, and employees in connection with their business. PG&E Corporation's and the Utility's risk management and information security measures may be ineffective, and the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information. If any of these events were to transpire, it could subject PG&E Corporation and the Utility to financial liability. PG&E Corporation and the Utility are subject to federal and state privacy laws, which grant consumers rights and protections, including, among other things, the ability to opt out of receiving certain communications and certain data sharing with third parties.

The Utility may be unable to manage its costs effectively. The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility's ability to achieve such savings depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system. Even if the Utility is able to reduce some costs, other emerging priorities, such as emergency response, public purpose programs, wildfire mitigation initiatives, or California's clean energy transition, could require it to reinvest those savings. Concerns about high rates for the Utility's customers could negatively impact PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. The rates paid by the Utility's customers are impacted by the Utility's costs, commodity prices, and broader energy trends. The Utility's capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customers' rates. In particular, the Utility will need to make substantial, sustained investments to its infrastructure to adapt to climate change, enable the clean energy transition, and mitigate wildfire risk. For more information on factors that could cause the Utility's costs to increase, see "The Utility's ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility's actual costs could exceed its authorized or forecasted costs due to various factors" above. The CPUC considers affordability as it adjudicates the Utility's rate cases, and concerns about affordability could cause the CPUC to approve lesser amounts in the Utility's ratemaking or cost recovery proceedings. The Utility generally recovers its electricity and natural gas procurement costs through rates as "pass-through" costs. Increases in the Utility's commodity costs directly impact customer bills. Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM and NBT, which allows self-generating customers to receive bill credits for power exported to the grid, shifts costs to other customers. Under this structure, NEM and NBT customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, including costs associated with funding social equity programs, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. These unpaid costs are subsidized by customers not participating in NEM or NBT. Accordingly, as more electric customers switch to the NBT and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM or non-NBT customers. Other long-term trends could also increase costs for gas customers. Natural gas suppliers are subject to compliance with CARB's cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). Increased renewable portfolio standards in the electric sector could also reduce electric generation gas load. CARB may also require aggressive energy efficiency programs to reduce natural gas end use consumption. Additionally, the Bay Area Air Quality Management District has adopted rules that restrict the sale of gas space and water heating appliances, and the CARB is considering similar rules. If other jurisdictions also adopt similar rules, reduced gas demand could accelerate customers replacing natural gas appliances with electric appliances. The combination of reduced load and increased costs to maintain the gas system could result in higher natural gas customer bills. In addition, some local city governments have passed ordinances restricting use of natural gas in new construction and, if other jurisdictions follow suit, this could affect future demand for the provision of natural gas. If fewer customers receive gas from the Utility, the Utility's gas system maintenance costs, many of which cannot be reduced in the short term even if gas quantities decrease, would be borne by fewer customers. Finally, a mandate to purchase renewable natural gas for core customers could lead to increased costs for core customers if utilities are competing with the transportation sector for supplies of renewable natural gas. 52 A confluence of technology-related cost declines, along with sustained or increased federal or state subsidies, could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility's bundled electric service which could further reduce energy demand. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could increase the energy rates for other customers. If rates were to rise too rapidly, customer usage or the number of customers could decline. A decrease in the volume of sales, among which the Utility's costs are allocated, could further increase rates.

•Outcomes of regulatory and ratemaking proceedings and the Utility's ability to manage its costs; and •Municipalization. Risks related to financial conditions, including risks related to: •PG&E Corporation's and the Utility's substantial indebtedness; •Restrictions in indebtedness documents; •Potential additional dilution to holders of PG&E Corporation common stock; •Ownership and transfer restrictions associated with PG&E Corporation common stock; •The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; •PG&E Corporation's reliance on dividends, distributions and other payments from the Utility; •Restrictions on shareholders' ability to change the direction or management of PG&E Corporation; 36 •Increased customer rates;

Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below.

Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. The electric power and natural gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could lead to the reduction in demand for natural gas as an energy resource that could impact the Utility's ability to recover the value of its investments through rates. The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, electric vehicles, electric heat pump space conditioning and water heating, battery electric storage, fuel cells, energy efficiency, and demand response technologies. These developments will require further modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid's capacity to interconnect these resources. In addition, enabling California's clean energy transition will require sustained investments in grid modernization, renewable energy integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure, and state infrastructure modernization (e.g., rail and water projects). The Utility may be unable to effectively adapt to these potential business and regulatory changes, for instance by failing to meet customer demand for new business interconnections in a timely manner. The CPUC is also conducting proceedings to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources and consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. If the Utility is unable to effectively adapt to these potential business and regulatory changes, its business model and its ability to execute on its strategy could be materially impacted. Various jurisdictions within California have enacted prohibitions or restrictions on use and consumption of natural gas, for example in buildings, that will reduce the use of natural gas. Reducing natural gas use reduces the gas customer base and could diminish the need for gas infrastructure and, as a result, could lead to certain gas assets no longer being "used and useful" (under CPUC precedent, when an asset no longer meets the standard of "used and useful," the asset is removed from rate base, which may result in a reduction in associated rate recovery). In that case, gas assets with substantial investment value could become stranded, resulting in accelerated depreciation or impairment of assets. The Utility could also be required to incur significant decommissioning costs, which may require additional funding. However, even as natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. If the Utility is unable to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability, its financial condition, results of operations, liquidity, and cash flows could be materially affected. 42 These industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility's inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility's financial condition, results of operations, liquidity, and cash flows.

The Utility's operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack. The Utility's electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events such as severe weather or seismic events and by malicious events, such as physical and cyber attacks. Nationally, there has been an increase in physical attacks on substations. Physical attacks targeting the Utility's physical assets or personnel could cause damage, disrupt operations, or cause injuries. Cyber attacks targeting utility systems are significant and are continuing to increase in sophistication, magnitude, and frequency. Any failure, interruption, or decrease in the functionality of the Utility's operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility's ability to safely generate, transport, deliver and store energy and gas or otherwise operate in a safe and efficient manner or at all, and damage the Utility's assets or operations or those of third parties. The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store, and otherwise process sensitive information, including the Utility's financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals, and portions of such sensitive information may be required to be encrypted by the Utility. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California's electricity market related to grid modernization and customer choice. The Utility often relies on third-party vendors to host, maintain, modify, and update its systems (including providing security updates), and to provide other services to the Utility or the Utility's customers. These third-party vendors could cease to exist, fail to adopt and implement adequate processes to protect the Utility's systems and information, fail to provide timely software updates (and even if timely provided, there could be a delay in the installation of the updates), fail to detect security vulnerabilities, or experience security incidents or inadequate security measures. Any such incidents or disruptions in the Utility's information technology systems could impact the Utility's ability to track or collect revenues and to maintain effective internal controls over financial reporting. PG&E Corporation and the Utility face various cybersecurity threats, including attempts to gain unauthorized access to their systems and networks, denial-of-service attacks, threats to their information technology infrastructure, ransomware and phishing attacks, and attempts to gain unauthorized access to confidential or sensitive information about the Utility, customers and employees. These threats come from a variety of highly organized actors, including nation-state actors. PG&E Corporation, the Utility and their third-party vendors have been subject to, and will likely continue to be subject to, threats, breaches and attempts to gain unauthorized access to the Utility's information technology systems or confidential or sensitive data (including information about customers and employees), or to disrupt the Utility's operations. Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats, and PG&E Corporation's and the Utility's use of generative artificial intelligence (and use by their vendors and agents) may subject them to data privacy, legal, and security risks. The Utility may not be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, lawsuits, and regulatory actions and could result in material fines, penalties, loss of customers, and harm to PG&E Corporation's and the Utility's reputation, any of which could have a material effect on PG&E Corporation's and the Utility's business strategy, financial condition, or results of operations. For more information, see Item 1C. Cybersecurity. The Utility maintains cyber liability insurance that covers certain losses and damages caused by cyber incidents, but adequate insurance may not continue to be available at rates the Utility believes are reasonable, or the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable through rates. 43 The operation and decommissioning of the Utility's nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire.

The Utility may be unable to attract and retain specialty personnel and may face workforce disruptions. The Utility's workforce is aging, and many employees are or will become eligible to retire within the next few years. The Utility's efforts to recruit and train new field service personnel may be ineffective, and the Utility may be faced with a shortage of experienced and qualified personnel in certain specialty operational positions, such as certain positions at DCPP. Additionally, the Utility could experience workforce disruptions from personnel in those positions as a result of labor activity, pandemics, or governmental regulation of pandemic protections. If the Utility were to experience such a shortage or disruptions, work stoppages could occur.

Risks related to wildfires, including risks related to: •The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires; •The 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires;

The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with such regulations could result in penalties. The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with matters that the CPUC's SED may investigate. The SED can launch investigations at any time on any issue it deems appropriate. In addition, the OEIS has authority to approve and oversee compliance with the WMP and may determine that the Utility has failed to substantially comply with its WMP. The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; wildfire mitigation initiatives (including EPSS, PSPS, vegetation management, asset inspections, and system hardening); design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC general orders ("GOs") or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance. CPUC staff could also impose penalties on the Utility in the future in accordance with its authority under the gas and electric safety citation programs. The amount of such fines, penalties, or customer refunds depends on a variety of factors and could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. 47 The Utility also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. See "Risks Related to Wildfires" above. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions. The Utility is unable to predict the outcome of these pending or potential investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations. If these investigations result in enforcement action against the Utility, the Utility could incur additional fines, penalties, customer rebates, or other payments, the amount of which could be substantial, and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; for example, by enabling parties to challenge the Utility's request to recover costs that the parties allege are somehow related to the Utility's violations. The Utility's ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility's actual costs could exceed its authorized or forecasted costs. The Utility's financial results depend on its ability to earn a reasonable return on capital, including long-term debt and equity, and to recover costs from its customers, through the rates it charges its customers as approved by the CPUC and the FERC. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility or if the amount of actual costs incurred differs from the forecast or authorized costs embedded in rates. The outcome of the Utility's ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility's regulators, consumer and other stakeholder organizations, and customers, about the Utility's ability to provide safe, reliable, and affordable electric and gas services. If the CPUC does not authorize sufficient funding for investments in the Utility's infrastructure, it may negatively impact the Utility's ability to modernize the grid and make it resilient to risks related to climate change, including wildfires. In addition to the amount of authorized revenues, PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility's actual costs differ from authorized or forecast costs. The Utility's ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time delay between when costs are incurred and when those costs are recovered through rates. The CPUC or the FERC have not allowed and may in the future not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, the Utility has incurred, and continues to incur, wildfire mitigation and prevention costs before it is clear whether such costs will be recoverable through rates. OEIS has required and may in the future require the Utility to perform work for which the CPUC has not yet authorized recovery. Also, the CPUC may deny recovery of uninsured wildfire-related costs incurred by the Utility if the CPUC determines that the Utility was not prudent.

Risks Related to PG&E Corporation's and the Utility's Environment and Financial Condition PG&E Corporation's and the Utility's substantial indebtedness may adversely affect their financial health and operating flexibility. PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility. As of December 31, 2024, PG&E Corporation had approximately $5.65 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation's $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.5 billion aggregate principal amount of Junior Subordinated Notes due 2055, $1.0 billion aggregate principal amount of senior secured notes due 2028, and $1.0 billion aggregate principal amount of senior secured notes due 2030, and the Utility had approximately $51.9 billion of outstanding indebtedness. In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $3.8 billion of additional borrowing capacity under the Utility Revolving Credit Agreement and $1.5 billion under the Receivables Securitization Program. In addition, PG&E Corporation and the Utility had outstanding preferred stock with aggregate liquidation preferences of $1.6 billion and $258 million, respectively. Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility's assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets or using them for other financing transactions. This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: •limiting their ability or increasing the costs to refinance their indebtedness; •limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; •limiting their ability to use operating cash flow in other areas of their business; •increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and

•enter into any sale-leaseback transactions; and •enter into swap agreements. In addition, the Utility's DOE Loan Guarantee Agreement contains similar covenants as well as certain affirmative and negative covenants, events of default, and prepayment events which are incremental to those contained in the Utility's credit agreements and indentures. The restrictions contained in these material financing agreements could affect PG&E Corporation's and the Utility's ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation's and the Utility's ability to finance their operations and expenditures, make strategic acquisitions, investments, or alliances, sell assets, restructure their organization, or finance their capital needs. PG&E Corporation's and the Utility's ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions. Failure to comply with these covenants could result in an event of default, which, if not cured or waived, could accelerate PG&E Corporation's or the Utility's repayment obligations and could result in a default, acceleration or other consequences under other agreements. For example, a default on indebtedness in a principal amount in excess of $200 million could result in a cross-default or cross-acceleration. 50 PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims. On the Emergence Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in "Wildfire-Related Securities Claims-Claims in the Bankruptcy Court Process" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline. Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in "Wildfire-Related Securities Claims-Claims in the Bankruptcy Court Process" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). Such payment may have a material adverse impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. PG&E Corporation capital stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation's ability to use its net operating loss carryforwards and other tax attributes. PG&E Corporation has incurred and may also incur in the future significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the "capital stock") and other interests designated as "stock" of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the "Equity Securities," and such restrictions on transferability and ownership, the "Ownership Restrictions") in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation's ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid. Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the combined value of outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the combined value of the Equity Securities to increase their proportionate interest in the Equity Securities. Additionally, the application of the Ownership Restrictions, as defined in PG&E Corporation's Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility. See "Tax Matters" in Item 7. MD&A for an example of these calculations. Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.

PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to offset future income. As of December 31, 2024, PG&E Corporation had net operating loss carryforwards for PG&E Corporation's consolidated group for U.S. federal and California income tax purposes of approximately $33.7 billion and $34.9 billion, respectively, and PG&E Corporation incurred and may also continue to incur significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the IRC (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an "ownership change," such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate value of the 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). As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC. However, whether PG&E Corporation underwent an ownership change as a result of the transactions in PG&E Corporation's equity that occurred pursuant to the Plan or in combination with other changes in the ownership of PG&E Corporation's equity depends on several factors outside PG&E Corporation's control and the application of certain laws that are uncertain in several respects. Accordingly, the IRS may successfully assert that PG&E Corporation has undergone an ownership change pursuant to the Plan. If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. In particular, limitations imposed on PG&E Corporation's ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. Further, PG&E Corporation's ability to utilize its net operating loss carryforwards is critical to PG&E Corporation's and the Utility's commitment to make certain operating and capital expenditures. Failure to obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation capital stock. PG&E Corporation is a holding company and relies on dividends, distributions, and other payments, advances, and transfers of funds from the Utility to pay dividends on its capital stock and meet its obligations. PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation's consolidated assets are held by the Utility. Accordingly, PG&E Corporation's cash flow, ability to pay dividends on its capital stock, and ability to meet its debt service obligations under its existing and future indebtedness largely depend upon the earnings and cash flows of the Utility and the distribution of these earnings and cash flows to PG&E Corporation. The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and is restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in financing agreements. See "Liquidity and Financial Resources" in Item 7. MD&A. The Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to meet its obligations to employees and creditors, and to pay preferred stock dividends, before it can distribute cash to PG&E Corporation. In particular, the CPUC requires PG&E Corporation's and the Utility's Boards of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC also regulates the Utility's capital structure. Dividend payments on PG&E Corporation's capital stock are also subject to the discretion of PG&E Corporation's Board of Directors. See Note 6 of the Notes to the Consolidated Financial Statements included in Item 1. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility's ability to pay dividends or make other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation's ability to pay capital stock dividends or meet other obligations. 52

•Severe weather events, extended drought, and climate change and events resulting from these conditions (including wildfires); and •Extensive environmental laws.

Additionally, under the doctrine of inverse condemnation, courts have imposed liability against utilities on the grounds that losses borne by the person whose property was damaged through a public-use undertaking should be spread across the community that benefited from such undertaking, even if the utility is unable to recover these costs through rates. In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility's service area. Inverse condemnation imposes strict liability (including liability for attorneys' fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities' electric transmission lines. The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in litigation against PG&E Corporation or the Utility. 39 Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility's equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. The Utility's significant infrastructure investment, vegetation management, and de-energization strategies do not eliminate wildfire risk and may not prevent future wildfires. Once an ignition has occurred, the Utility is unable to control the extent of damages, which primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire. In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility's proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the annual safety certification. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires. For more information about the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility may be unable to recover all or a significant portion of its costs in excess of insurance coverage in connection with wildfires through rates. PG&E Corporation's and the Utility's accrued losses for the 2019 Kincade fire and the 2021 Dixie fire of $1.225 billion and $1.925 billion exceed the amounts of available liability insurance coverage of $430 million and $527 million, respectively. PG&E Corporation and the Utility could also incur substantial costs in excess of insurance coverage in connection with the 2022 Mosquito fire. As of December 31, 2024, the Utility has recorded probable recoveries of $602 million and $60 million for the 2021 Dixie fire and 2022 Mosquito fire, respectively, through FERC TO rates or as costs recorded to the WEMA. The Utility would not be allowed to recover these costs in excess of insurance to the extent that the CPUC or the FERC determines that they were incurred imprudently. The inability to recover all or a significant portion of costs in excess of insurance through rates could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. For more information on wildfire recovery risk, see "The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires" above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

•Increased customer rates; and •Inflation and supply chain issues. Risks Related to Wildfires The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires. If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the AB 1054 disallowance cap. Under AB 1054, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Wildfire Fund reimbursement and all aspects of the reformed prudent manager standard. The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company's actions or inactions that resulted in the applicable wildfire constituted "conscious or willful disregard for the rights and safety of others," or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited. In addition, if the Utility fails to maintain a valid safety certification at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility. The Utility will be required to reimburse amounts that are determined by the CPUC not to be just and reasonable. For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 38 Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than PG&E Corporation's and the Utility's 20-year estimate for the life of the Wildfire Fund (see Note 2 of the Notes to the Consolidated Financial Statements in Item 8), including as a result of claims made by California's other participating electric utility companies. For example, victims of wildfires in Southern California in January 2025 have filed lawsuits alleging that Southern California Edison's equipment was associated with the ignition of such fires. If the Utility is unable to maintain a safety certification or if the Wildfire Fund is exhausted, the ineffectiveness of the Wildfire Fund could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, there could be a significant delay between the occurrence of a wildfire and when the Utility recognizes impairment for the reduction in future coverage due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund may not ultimately outweigh the substantial costs of the Utility's contributions to the Wildfire Fund. PG&E Corporation's and the Utility's liabilities for the 2019 Kincade fire, the 2021 Dixie fire, or the 2022 Mosquito fire could exceed their accruals, or they could be liable as a result of future wildfires. Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire. PG&E Corporation's and the Utility's recorded liabilities for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. The Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have been the subject of investigations, regulatory enforcement actions, and criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to "make restitution to the victim or victims in an amount established by court order" that is "sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of" the Utility's underlying conduct, in addition to interest and the victim's or victims' attorneys' fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. There have been numerous other wildfires in the Utility's service area, of which the Utility has not been alleged or determined to be a cause. The Utility could be alleged or determined to be a cause of one or more of these wildfires.

Electricity Transmission Owner Rate Cases The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect through rates in TO rate cases. In its TO rate cases, the Utility uses a formula rate methodology, which includes an authorized revenue requirement and rate base for a given year but also provides for an annual update of the previous year's revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate are either collected from or refunded to customers. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. These FERC-approved rates are included by the CPUC in the Utility's retail electric rates and by the CAISO in its transmission access charges to wholesale customers. For more information, see "Regulatory Matters - Transmission Owner Rate Cases" in Item 7. MD&A. The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations. These wholesale customers are charged individualized rates based on the terms of their contracts.

Diversity, Equity, Inclusion, and Belonging PG&E Corporation's and the Utility's goal is to foster a diverse, equitable, and inclusive workforce culture where all employees find it enjoyable to work with and for PG&E Corporation and the Utility and feel they belong. These efforts are led by PG&E Corporation's and the Utility's Executive Vice President, Chief People Officer, in partnership with the executive team. The People and Compensation Committee of PG&E Corporation's Board of Directors reviews the companies' diversity, equity, inclusion, and belonging strategy, practices, and performance. Key elements of PG&E Corporation's and the Utility's approach to diversity, equity, inclusion, and belonging include integrating inclusion and belonging into the employee experience with a focus on equity and interrupting bias in hiring, promotion, retention and compensation, heightened cultural awareness programming to encourage understanding and importance of inclusion and belonging, and integrating useful content into training, development, and performance support resources. Additionally, the Utility's 12 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide employee programming, nominated employees lead efforts within their departments, and across the companies. Specialized teams facilitate awareness, education and dialogue and support the groups at the enterprise level. In 2024, women, minorities, and military veterans accounted for approximately 26%, 50%, and 7%, respectively, of total PG&E Corporation and Utility employees. The Utility's employees represent five generations, most of whom are Millennials (49%), Generation X (37%), and Boomers (10%). Generational data refers to "Millennials" for individuals born between 1981 and 1996, "Generation X" between 1965 and 1980, and "Boomers" between 1946 and 1964.

TOTAL100 %- %100 % Total renewable energy resources (3) 23 %- %23 % GHG-free resources (6) 98 %- %98 % (1) This amount excludes electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers. (2) The allocation of "Others, net" in the "CEC Reporting Methodology Adjustment" and "Power Content Label" columns is consistent with current CEC guidelines as an adjustment mechanism to apply, as specified. Total reported generation and procurement volumes equate to actual electric retail sales. (3) Amounts include biopower (e.g., biogas, biomass), solar, wind, certain hydroelectric (i.e., 30MW or less), and geothermal facilities. The eligible renewable percentages above do not reflect RPS compliance, which is determined using a different methodology.

In 2023, the Utility spent $4.18 billion with certified diverse suppliers, representing 36.6% of its total spend. Performance: Underpinning the Triple Bottom Line PG&E Corporation and the Utility use the Lean operating system, which includes five basic "plays": visual management; operating reviews; problem solving; standard work; and waste elimination. Visual management allows teams to see how they are performing against their most important metrics using real-time data. Teams throughout PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of employees closest to the work with the goals and objectives of senior leadership. These brief meetings help the Utility identify gaps and quickly develop plans to support the teams performing the work and give the Utility more visibility, control and predictability in its operations. Problem solving involves a structured approach to identifying, containing, analyzing, and solving problems in order to capitalize on opportunities. Standard work reduces costs and increases productivity by establishing a consistent company-wide method for completing a task. For instance, the Lean operating system helped the Utility identify patterns in the conditions of ignitions and led to the implementation of EPSS, which drove a significant reduction in facility ignitions. PG&E Corporation's and the Utility's performance is also driven by an increased focus on alignment of shared outcomes among its leadership and within the organization. Waste elimination, the fifth Lean play, was deployed in 2023 and enables the companies to identify and eliminate inefficiencies in both process and workflow in a sustainable manner and drive the continued adoption of consistent processes and improvements to financial visibility and controls. In 2023, the Utility implemented PG&E's Safety Excellence Management System, which is a more systematic approach to assess risk and evaluate or implement controls for safe operation based on industry standards. PG&E Corporation and the Utility have implemented a regional service model to bring the Utility closer to the hometowns it serves. Through the regional service model, the Utility has restructured its service area into five regions, with leaders assigned for each region to deliver improved public and employee safety, customer service, and operational reliability outcomes. California has experienced unprecedented weather conditions in recent years and the Utility's service area remains susceptible to additional wildfire activity. In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including: •Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them in less than one-tenth of a second in the event of a disturbance to help prevent potential ignitions. In recent years, the Utility expanded the EPSS program to all high fire risk areas and reviewed and adjusted settings to improve coordination among devices on a circuit to reduce the number of customers impacted by an outage. After EPSS was initiated, both the size and number of CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average. •Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions. Since its inception in late 2017, the PSPS program has become more targeted through the use of more granular risk models, including incorporating more detailed data inputs. The Utility has also installed sectionalizers for more targeted de-energizations of circuits and transmission lines. These more targeted scoping criteria are engineered to reduce the number of customers impacted by any particular PSPS event. In 2024, the Utility executed six PSPS events impacting a total of approximately 50,000 customers. 15 •Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and clear vegetation that might grow or fall into utility equipment. •Asset inspections: Since 2018, the Utility has reoriented its asset inspections programs toward asset condition and consequence risk, particularly wildfire risk, and these programs have become more thorough, standardized, digitized, and verifiable. The Utility uses risk-informed inspection cycles. In 2024, the Utility continued to refine its inspection techniques, transitioning to the use of aerial drones to perform inspections on circuits located in HFTD areas. As a result of the improved inspection program, the Utility's inspections in 2024 have further enhanced its ability to identify equipment conditions. •System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTD areas and installing stronger and more resilient equipment. As the Utility's asset inspections have identified less resilient equipment, the Utility has hardened its system by fixing significantly more equipment than in prior years. Hardening methods also include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground. The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. In 2024, the Utility undergrounded 259 miles of lines. When feasible, remote grids can be a more cost-effective option to reduce fire risks by permanently disconnecting end-of-line customers from the grid and serving them with utility owned, locally sited resources. The Utility brought online five additional remote grids in 2024, for a total of 11 remote grids overall.

PG&E Corporation's and the Utility's operating revenues, income, and total assets can be found below in Item 8. Financial Statements and Supplementary Data. The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation's telephone number is (415) 973-1000 and the Utility's telephone number is (415) 973-7000. This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity. This 2023 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors and "Forward-Looking Statements" above.

For more information, see "Human Capital" below. Planet The planet element of the triple bottom line represents PG&E Corporation's and the Utility's commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations. PG&E Corporation and the Utility believe that integrating and managing climate change and other environmental considerations in the companies' business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, coworkers, and other stakeholders. Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility's business and economic opportunity for the communities it serves. The Utility is committed to delivering safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards. To build resilience to these hazards, the Utility is working to systematically integrate forward-looking climate data and tools into its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate change policy in California, and work directly with local governments and communities on adaptation solutions. PG&E Corporation and the Utility are also committed to helping heal the planet. PG&E Corporation's and the Utility's Climate Strategy Report, which is available to the public, describes the companies' climate goals and plans to meet those goals. To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the energy system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased penetration of renewable energy combined with investments in the grid and energy storage. PG&E Corporation and the Utility are also making progress on transitioning the gas system to cleaner fuels and supporting efforts to accelerate building electrification. The objective is to do so in an orderly manner to achieve a positive customer and community experience, while reducing natural gas system investments in targeted electrified communities. The impacts of climate change on the Utility's infrastructure are already a reality. Record-breaking extreme heat and heat waves are increasingly a regular occurrence throughout California. Peak electric loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage, and increasingly driven in the future from widespread progress in adoption of strategic electrification technologies. The Utility's assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise. 12 Climate change will also continue to intensify the potential for wildfires throughout California. The worsening conditions across California increase the likelihood and severity of wildfires, including those where the Utility's equipment may be alleged to be associated with the fire's ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility. A key element of preparing the Utility for the physical risks of climate change is an updated and more detailed system-wide CVA of the Utility's assets, operations, and services, which the Utility expects to file with the CPUC in mid-2024. The CVA is expected to improve the Utility's understanding of its exposure to climate hazards and the sensitivity of assets and operations to these hazards. PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, and affordable clean and resilient energy for their customers. As a result of actions already taken by PG&E Corporation and the Utility, the companies have:

Energy Storage Energy storage improves system reliability and supports California's decarbonization goals by integrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, under which the Utility was required to procure 580 MW of qualifying storage capacity by the end of 2020, with all energy storage projects required to be operational by the end of 2024. As of December 31, 2023, the Utility was on track to meet its storage goals by the end of 2024. Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023. In January 2022, the Utility also requested CPUC approval for another 1,600 MW of storage to be completed by the summer of 2024, which would bring the Utility's total energy storage system capacity to more than 3,330 MW. Finally, the Utility is soliciting 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2026 and 2028. In order to address both its bundled portfolio need and to help to meet State planning and policy objectives to increase long-duration storage capacity after 2028, the Utility is pursuing regulatory approval to increase the nameplate generating capacity of its Helms Pumped Storage Facility. 30

•Delivered electricity to customers in 2023 that was 100% GHG free (see "Electricity Resources" below for more information). •Helped customers avoid emissions and manage energy costs through robust energy efficiency programs. •Managed contracts for more than 3.5 GW of battery energy storage to be deployed over the next several years and operated 183 MW of Utility-owned battery storage, strengthening California's grid efficiency and reliability. •Helped enable the total number of electric vehicles operating in the Utility's service area to exceed 550,000; installed more than 475 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and launched a first of its kind vehicle-to-grid program enabling customers to leverage their electric vehicles to power their home. •Brought the total number of interconnected private solar customers to more than 800,000 and supported more than 70,000 customers who have installed battery storage at their homes or businesses. •Continued to advance decarbonization initiatives for the Utility's natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule and accelerated initiatives to meet its voluntary 2030 reduction goal. The Utility also launched an initiative to purchase California-produced renewable natural gas for its natural gas customers, toward a target to procure renewable natural gas to serve 15% of its bundled residential and small commercial demand by 2030. The CPUC coordinates the planning of supply resources through the Integrated Resource Planning ("IRP") proceeding and has determined that replacing the power generated by Diablo Canyon is the responsibility of all LSEs within the CAISO. Looking ahead, the Utility expects its GHG-free energy supply mix of renewable, large hydroelectric, and nuclear generation resources to decrease as, beginning in 2023, the Utility was required to offer, for allocation or sale, renewable sources eligible under California's RPS program that the Utility procured on behalf of customers that subsequently switched to non-Utility providers. These requirements were established to comply with regulatory mandates and to manage customer affordability. Towards the end of the decade and beyond, the Utility's GHG-free energy supply mix is expected to grow relative to 2025 levels as the Utility procures new GHG-free generation and storage to meet California's IRP GHG emissions reduction targets and California's clean energy goals. PG&E Corporation's and the Utility's voluntary goal continues to be to deliver 70% RPS clean electricity by 2030, compared to a state mandate of 60% (see "Air Quality and Climate Change" below for more information).

Elkhorn Battery Energy Storage SystemMonterey County1 183 Photovoltaic (3): Various13 152 Total127 7,820 (1) The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. The NRC operating licenses currently expire in 2024 and 2025, respectively. For more information, see "Extension of Diablo Canyon Operations" in Item 7. MD&A below. (2) The Utility's hydroelectric system consists of 99 generating units at 61 powerhouses. All of the Utility's powerhouses are licensed by the FERC (except for two small powerhouses not subject to the FERC's licensing requirements), with license terms between 30 and 50 years. (3) The Utility's large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW). All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County. The Utility has applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. (For more information, see "Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets" in Item 7. MD&A below.)

State Regulation California laws and regulations have established the following targets: •A 40% reduction in GHGs by 2030 compared to 1990 levels. •50% of retail energy sales to customers from renewable energy sources by 2026 and 60% by 2030.

•System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTDs and installing stronger and more resilient equipment. As the Utility's asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions than in prior years. Hardening methods also include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground. The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. In 2023, the Utility undergrounded 364 miles of lines, nearly double the number of miles undergrounded in 2022. Remote grids can also reduce costs and fire risks, while maintaining service to participating customers. The Utility brought online two additional "remote grids" in 2022, which allow distribution lines in HFTDs to be removed and replaced with locally sited resources. The Utility's equipment was not involved in the ignition of any catastrophic wildfires in 2023. The Utility also significantly reduced both the size and number of CPUC-reportable ignitions and number of acres burned in 2023, compared to prior years. In 2023, the Utility introduced or expanded its use of several measures including downed conductor detection, partial voltage force outs, and transmission operational controls which further decreased wildfire ignition risk. These measures built on the Utility's progress in 2022, when it expanded the EPSS program to all high fire risk areas. In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for wildfire risk reduction when needed and enhancing reliability when wildfire risk is low. In 2022, the Utility reviewed and adjusted settings to improve coordination among devices on a circuit to reduce the number of customers impacted by an outage. In 2022 and 2023, the Utility took additional steps to improve customer reliability through several targeted programs, including vegetation management activities to reduce vegetation caused outages, upgrading the system to improve sectionalization, and installing fault indicators to reduce restoration times. PG&E Corporation and the Utility are continuing to invest in a safe and reliable gas system and are working toward targeted electrification, greening the gas supply, and shaping California energy policy. The Utility has focused on continuously improving its gas operations safety record. Since the San Bruno natural gas pipeline explosion in 2010, the Utility's asset safety efforts have included replacing distribution mains and transmission pipelines, as well as strength testing transmission pipelines. The Utility uses in-line inspections to assess the integrity of transmission pipelines. The Utility also uses safety and control systems to monitor, gather, and process real-time data on its gas system. The Utility's gas system has not had a safety-related incident that affected the public and resulted in a fatality or injury since 2015 or 2018, respectively. In 2023, the NTSB confirmed that the Utility had successfully addressed all 12 safety recommendations relating to the San Bruno explosion. The Utility has engaged in educating employees, contractors, and the public regarding safe digging programs and practices for their awareness during construction and when digging near the Utility's underground gas and electric assets. The Utility also installed safety devices that automatically detect increasing pressure on systems and stop the flow of gas to avoid outages and overpressure events. Additionally, the Utility continues to streamline its efforts to respond to outages on a timely basis. The Utility's outage response is designed to keep the public safe while limiting customer outages and returning service safely and as quickly as possible. The Utility's generation operations have focused on safety and reliability. Winter precipitation and snowpack provided fuel for increased hydro generation in 2023, exceeding the 15-year average. The Utility is focused on continuous improvement of asset management and work management systems to support comprehensive non-nuclear generation asset management. The goal of these efforts is to further improve project execution capabilities and capacity to deliver on asset improvements necessary for long-term safe and reliable generation.

Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Utility's two nuclear generating units at DCPP and the Utility's independent spent fuel storage installation at Humboldt Bay. See "Electricity Resources" below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated that the Utility incur substantial costs at DCPP, and substantial costs could be required in the future. For more information about DCPP, see Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Air Quality and the Clean Air Act The Utility's electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and other emissions.

The Utility's costs of equity and long-term debt are generally approved in the CPUC's cost of capital proceedings. As a result, the Utility's CPUC-jurisdictional revenue requirement is the sum of the following: •expenses; •depreciation; 20

See "Regulatory Matters" in Item 7. MD&A for more information on specific CPUC proceedings. Base Revenues General Rate Cases The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility's anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base. The CPUC conducts a GRC every four years that includes the Utility's costs of its gas transmission and storage facilities. The CPUC approves the annual revenue requirements for the first year (or "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"). Attrition year rate adjustments are generally authorized for cost increases related to invested capital and inflation. Parties to the Utility's GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the interests of residential customers, as well as numerous intervenors that represent other business, community, customer, environmental, and union interests. For more information about the Utility's GRC, see "Regulatory Matters - 2023 General Rate Case" in Item 7. MD&A.

Cost of Capital Proceedings The CPUC periodically conducts a cost of capital proceeding to authorize the Utility's ratemaking capital structure (i.e., the relative weightings of common stock, preferred equity, and debt for ratemaking) and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. The rate of return, or cost of capital, is the weighted average cost of debt, preferred equity, and common stock a utility has issued to finance its utility capital investments. The CPUC's cost of capital proceedings generally take place in a consolidated proceeding with California's other large investor-owned electric and gas utilities. For more information about the cost of capital proceedings, see "Regulatory Matters - Cost of Capital Proceedings" in Item 7. MD&A. 21

Diablo Canyon Extended Operations During the period of extended operations and in lieu of the traditional rate-based return on investment, SB 846 provides for a fixed payment of $50 million, in 2022 dollars, for each of DCPP's Unit 1 and Unit 2 for each year of extended operations to be recovered from customers of all CPUC-jurisdictional LSEs, which is potentially subject to adjustment downward in the event of extended unplanned outages. In addition, SB 846 authorizes a volumetric payment totaling $13 (in 2022 dollars) for each MWh generated by DCPP during the period of extended operations, with the first half recovered from all CPUC-jurisdictional LSEs and the second half from customers in the Utility's service area. The amount of the fixed and volumetric payments will be adjusted annually by the CPUC using CPUC-approved escalation methodologies and adjustment factors. The volumetric payment cannot be realized as shareholder profits or paid out as dividends, to the extent it is not needed for DCPP. The legislation includes language that limits use of the volumetric payment to accelerate, or increase spending on, public purpose priorities enumerated in SB 846.

Revenues to Recover Energy Procurement and Other Pass-Through Costs Electricity Procurement Costs California IOUs are responsible for procuring electrical capacity required to meet bundled customer demand, plus applicable reserve margins. The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties, into the wholesale market to meet customer demand according to which resources are the least expensive (i.e., using the principles of "least-cost dispatch"). In addition, the utilities are required to obtain CPUC approval of their BPPs based on long-term demand forecasts. In October 2015, the CPUC approved the Utility's most recent comprehensive BPP. It has been revised since its initial approval, and the revised version will remain in effect, subject to any further revisions, until superseded by a subsequent CPUC-approved plan. 22 California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved BPPs without further after-the-fact reasonableness review by the CPUC. The CPUC may disallow costs associated with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch. Additionally, the CPUC may disallow the value of lost generation due to unplanned outages at utility-owned generation facilities. The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. Each year, the CPUC reviews the Utility's forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement. The CPUC may adjust the Utility's retail electric rates more frequently if the forecasted aggregate over-collections or under-collections in the Energy Resource Recovery Account, net of bundled service customer Portfolio Allocation Balancing Account balances, exceed five percent of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the procurement transactions recovered in various balancing accounts, including the Energy Resource Recovery Account and the Portfolio Allocation Balancing Account. The CPUC has approved various power purchase agreements into which the Utility has entered with third parties in accordance with the Utility's CPUC-approved BPP, to meet mandatory renewable energy targets, and to comply with RA requirements. For more information, see "Electric Utility Operations - Electricity Resources" below as well as Note 15 of the Notes to the Consolidated Financial Statements in Item 8. The Utility is also responsible, as the central procurement entity ("CPE") for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all CPUC-jurisdictional LSEs in its distribution service area. CPUC decisions grant the Utility, acting as CPE, discretion to defer procurement of local resources to the CAISO's backstop mechanisms if bid costs are deemed unreasonably high. The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, so long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met. In addition, the Utility, as the CPE, has been ordered or authorized to seek to procure specific local capacity products pursuant to CPUC decisions. In connection with its CPE function, the Utility is responsible for making compliance demonstrations to the CPUC and the CAISO. The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account. The CPUC may disallow costs associated with the CPE function that were not incurred in compliance with the CPUC's decisions and guidance. The CPUC has also approved the Power Charge Indifference Adjustment ("PCIA"). The PCIA is a cost recovery mechanism to ensure that customers who switch from the Utility's bundled service to a non-Utility provider, such as a DA or CCA provider, pay their share of the above-market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf.

People The people element of the triple bottom line represents PG&E Corporation's and the Utility's commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders. 12 PG&E Corporation's and the Utility's goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe. Their focus is on continuously building an organization where every work activity is designed to facilitate safe performance, every worker knows and practices safe behaviors, and every individual is encouraged to speak up and stop work if they see unsafe or risky behavior, and has confidence that their concerns and ideas will be heard and pursued. PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction. PG&E Corporation's and the Utility's human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitably-paid workforce. Their focus is on making it enjoyable to work with and for PG&E Corporation and the Utility. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility's customer-driven investment program is aimed at improving safety, increasing electric and gas service reliability, and improving customer satisfaction.

Nuclear Decommissioning Costs The Utility's nuclear power facilities consist of two units at DCPP and the Humboldt Bay independent spent fuel installation. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. Nuclear decommissioning costs are generally collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. The Utility files an application with the CPUC, generally every three years, requesting approval of the Utility's updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility's nuclear facilities. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers. Pursuant to Public Utilities Code Section 8325, to the extent the monies available for decommissioning are insufficient to pay for all reasonable and prudent decommissioning costs, the CPUC must authorize the electric utility to collect these charges from its customers.

Employees and Contractors As of December 31, 2024, PG&E Corporation had 10 employees and the Utility had approximately 28,400 regular employees. Of the Utility's regular employees, approximately 17,600 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers ("IBEW") Local 1245; the Engineers and Scientists of California ("ESC") IFPTE 20; and the Service Employees International Union Local 24/7 ("SEIU"). The collective bargaining agreements in effect for the IBEW Local 1245, ESC Local 20, and SEIU United Service Workers West, are set to expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits. The IBEW, ESC, and SEIU represent approximately 62% of the Utility's employee workforce and support several areas of the Utility's business, including gas and electric operations. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2024. 24 PG&E Corporation's employees are primarily at the executive management level. The Utility generally has a stable workforce. The Utility's turnover rate for each of 2024 and 2023 was 4.0%. Approximately 44% of PG&E Corporation's and the Utility's employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 18% of PG&E Corporation's and the Utility's employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

All executive officer compensation is paid by PG&E Corporation. 25 Safety The Utility's strategy to deliver on safety outcomes focuses on employee, contractor, and public safety. Identifying, eliminating and mitigating high-energy hazards remains a priority. The Utility's safety metrics include the number of actual serious incidents or fatalities ("SIF-A") and high-energy events that could have resulted in a serious injury or fatality ("SIF-P") where SIF-P rate measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2024, the Utility had seven SIF-A incidents, which resulted in zero fatalities and seven serious injuries, and a SIF-P rate of 0.05. Additionally, the Utility measures DART (days away, restricted or transferred duty per 200,000 hours worked). In 2024, the Utility's DART was 0.7. In particular, the Utility improved safety through the implementation of the Utility's safety excellence management system and a focus on essential controls for high energy hazards.

Electricity Resources The Utility is required to maintain adequate capacity to meet its customers' demand for electricity ("load"), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. The following table shows the percentage of the Utility's estimated total net deliveries of electricity to retail customers in 2024 represented by each major electric resource, and further discussed below. The Utility's deliveries were primarily from renewable energy resources that qualify under California's RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California's RPS requirements and SB 100 goal is to serve 100% of retail electricity sales with GHG-free resources by 2045. For more information about California's RPS requirements and clean energy goals, see further below and in the "Sustainability and Resiliency" section below. 26

(4) Amounts consist primarily of natural gas facilities. (5) Amount is mainly comprised of net CAISO open market (sales)/purchases. (6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold.

(7) Amount includes adjustments due to DCPP's extended operations, consistent with CPUC and CEC guidelines. Renewable Energy Resources California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. See "Sustainability and Resiliency" below. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets. The Utility expects that these costs will continue to be recoverable through rates as "pass-through" costs. The Utility also may be subject to penalties for failure to meet the higher targets. Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated to comprise 23% of total annual retail sales in 2024. Per the Power Content Label methodology based on current CEC guidelines presented in the table above, an estimated 23% of the Utility's energy deliveries were from renewable energy sources in 2024. 27

The estimated total renewable deliveries for the year ended December 31, 2024, shown above was 5,920 GWh and comprised of the following: TypePercent of Customer Retail Sales (estimated procurement)(1)

Biopower3 % Geothermal- % RPS-Eligible Small Hydroelectric2 % Solar15 % Wind3 % Total23 % (1) Estimated renewable procurement percentages above and renewable compliance percentages are expected to be consistent; however, final RPS compliance reporting is subject to a different methodology and may result in differences between the two percentages.

Generation TypeCounty LocationNumber of UnitsNet Operating Capacity (MW) Nuclear (1): Diablo CanyonSan Luis Obispo2 2,240 Hydroelectric (2): Conventional16 counties in northern and central California91 2,628

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility's regulators and the CAISO. Electricity Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to customers. The Utility's electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2024, approximately 27% are underground and approximately 73% are overhead), 59 transmission and distribution substations, and 603 distribution substations with a capacity of approximately 33,000 MVA. The Utility's distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, suitable for distribution to the Utility's customers. These distribution substations serve as the central hubs for the Utility's electric distribution network. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to customers. In some cases, third parties, such as municipal and other utilities, who generate or procure their own power rely upon the Utility's distribution facilities to deliver their power to them, so that they are able to resell the electricity. The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility's efforts to create a smarter, more resilient grid. 29

Industrial0.1475 0.1294 0.1177 Agricultural0.3597 0.2984 0.2435 Net plant investment per customer$11,460 $10,720 $9,967 (1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. On December 31, 2024, the Utility's natural gas system consisted of approximately 45,200 miles of distribution pipelines, approximately 5,700 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one compressor station on its local transmission system that are used to move gas through the Utility's pipelines. The Utility's backbone transmission system is used to transport gas from the Utility's interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility's local transmission and distribution systems. The Utility has firm transportation agreements for the transportation of natural gas from various natural gas supply points and interconnection points to the Utility's natural gas transportation system. These agreements provide transportation service from western Canada to the United States-Canada border, from the United States-Canada border to an interconnection point with the Utility's natural gas transportation system at the Oregon-California border, from the U.S. Rocky Mountains to an interconnection point with the Utility's natural gas transportation system at the Oregon-California border, and from supply points in the southwestern United States to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona. (For more information regarding the Utility's natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility's gas transmission system. In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility's owned and operated gas storage fields, Pleasant Creek and Los Medanos. The sale of Pleasant Creek is currently pending CPUC review and approval and the Utility anticipates to close on the sale in 2025. The Utility continues to operate and rely on the Los Medanos storage field as filed and approved in the 2023 GRC. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later for withdrawal. In addition, four independent storage operators are interconnected to the Utility's Northern California gas transmission system.

In 2024, the Utility continued upgrading transmission pipelines to allow for the use of in-line inspection tools. 31 Natural Gas Operating Statistics The following table shows the Utility's operating statistics from 2022 through 2024 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2024, 2023 or 2022.

Under cost-of-service ratemaking, a utility's earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. See "Ratemaking Mechanisms" below and "Regulatory Matters" in Item 7. MD&A for more information on specific CPUC and FERC proceedings. Generally, differences between forecast costs and actual costs can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. Costs can also decrease due to improved efficiencies or waste elimination. PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing PG&E Corporation's debt by $2 billion by the end of 2026. All three credit ratings agencies have increased PG&E Corporation's and the Utility's issuer credit ratings since 2020. 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. For more information, see "Liquidity and Financial Resources - Dividends" in Item 7, MD&A and Note 6 of the Notes to the Consolidated Financial Statements. Total capital expenditures recorded in 2024 were $10.6 billion. The Utility's total capital expenditures (including accruals) are forecasted to be $12.9 billion for 2025, $12.0 billion for 2026, $13.6 billion for 2027, and $14.0 billion for 2028. The Utility has identified additional opportunities for investment in the coming years in addition to its forecast, including investments in transportation electrification capacity, FERC-jurisdictional assets, electric distribution capacity, hydroelectric facilities, energy storage, information technology, and automation. The Utility also plans to submit a cost recovery application for its 10-year distribution undergrounding program pursuant to SB 884. Some of these investments depend on the Utility's ability to generate or obtain the cash to support such investments over this period of time. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather, and other unforeseen conditions. The Utility expects to make additional capital expenditures, the recovery of which will be subject to future regulatory approval. These expenditures include capital expenditures exceeding amounts authorized in the 2023 GRC final decision and expenditures to be included in a later filing or separate applications. These expenditures are expected to be primarily for wildfire mitigation and electrification. Additionally, $3.21 billion of fire risk mitigation capital expenditures has been excluded from the Utility's equity base rate pursuant to AB 1054. 14 PG&E Corporation and the Utility are committed to building a safe, reliable, sustainable, and climate-resilient energy system at the lowest possible cost for customers. The Utility's capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements collectively place continuing upward pressure on customer rates. Certain CPUC proceedings could impact different types of customers differently. The Utility has set a goal to increase customer capital investments while also limiting customer bill impacts, including by achieving operating cost savings, seeking efficient financing, and benefiting from electric load growth. The Utility plans to meet its cost savings goal through increased efficiencies including waste elimination through the Lean operating system. The Utility expects electric vehicle adoption, data centers, and building electrification to drive load growth. However, the scale of this growth will depend on the Utility's ability to construct necessary infrastructure and the extent of customer demand. The Utility has a number of programs in place to assist low-income customers, such as the CARE program. Under the CARE program, income-qualified customers can receive a monthly discount of 20% or more on their natural gas and electric bill. PG&E Corporation's and the Utility's Corporate Sustainability Report, which is available to the public, describes the companies' progress toward world-class performance measured with the triple bottom line framework.

Subtotal6,047 6,196 6,055 Regulatory balancing accounts (2) 561 808 565 Total operating revenues$6,608 $7,004 $6,620 Selected Statistics: Average annual residential usage (Mcf)37 37 37

Competition Trends in Market Demand and Competitive Conditions in the Electricity Industry The Utility expects customer electric load to increase in coming years primarily as a result of electric vehicle adoption, data centers, and building electrification. The Utility is not able to predict how quickly this electrification will occur. The Utility expects customer demand for gas to decrease in the coming years, primarily in response to policies supporting California's climate goals. California law allows qualifying non-residential electric customers of IOUs to purchase electricity from energy service providers rather than from the utilities up to certain annual limits specified for each utility. This arrangement is known as DA. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility. The Utility continues to provide transmission, distribution, metering, and billing services to DA customers at the election of their energy service provider. The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of DA and CCA customers while they were the Utility's customers. The Utility remains the electricity provider of last resort for these customers. Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. The Utility is also impacted by an increasing quantity of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, put upward rate pressure on non-NEM customers. The successor to the NEM tariffs, the NBT provides bill credits at a lower rate, which reduces the level of upward rate pressure on non-NEM or non-NBT customers, but does not eliminate the upward rate pressure. NEM and NBT customers are required to pay an interconnection fee, utilize time of use rates, and pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for non-NEM or non-NBT customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. See "Concerns about high rates for the Utility's customers could negatively impact PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows" in Item 1A. Risk Factors and "Regulatory Matters - Order Instituting Rulemaking ("OIR") to Revisit Net Energy Metering Tariffs" in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers, in some cases bypassing the Utility's electric infrastructure entirely. Those entities may also rely upon FERC open access tariffs and Utility infrastructure to deliver their energy for resale at retail to existing or potential new Utility customers. These entities may also seek to acquire the Utility's transmission or distribution facilities through eminent domain for use in serving electricity at retail to existing or potential new Utility customers. As a result, the Utility could lose customers (residential, commercial, and industrial) or experience limited growth in the municipality. See "Jurisdictions attempt to acquire the Utility's assets through eminent domain, and third parties attempt to acquire the Utility's customers by bypassing the Utility's electric infrastructure system" in Item 1A. Risk Factors. It is also expected that some publicly-owned utilities will build new or duplicate transmission or distribution facilities to serve existing or potential new Utility customers, bypassing the Utility's electric infrastructure. In some instances, microgrid formation is a key factor in a community's choice to engage governmental entities. Some private companies have also called for changes in law that could allow those companies to privately serve electricity to retail customers without being regulated by the CPUC as public utilities. To the extent such changes occur and result in large customers reducing the share of transmission, distribution, and non-bypassable charges they pay, PG&E Corporation's and the Utility's financial condition and results of operations could be materially impacted. The effect of such types of retail competition generally is to reduce the number of utility customers, leading to decreased growth or a reduction in the Utility's rate base. The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service area through a competitive bidding process managed by the CAISO.

•Renewable and zero-carbon resources supplying 90% of utilities' retail sales to customers by 2035, 95% by 2040, and 100% by 2045. The CARB has also approved GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or "caps") on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy. The cap-and-trade program has been extended through 2030. The CARB plans to update the cap-and-trade regulation in 2025 and is considering reforms that would reduce overall allowance budgets to align with CARB's 2022 Climate Change Scoping Plan. 34 During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Entities with a compliance obligation can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits (e.g., credits for GHG reductions achieved by third parties, such as landowners, livestock owners, and farmers, that occur outside of the entities' facilities through CARB-qualified offset projects such as reforestation or methane capture projects). The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers. The cap-and-trade program applies to the electric generation, large industrial, natural gas, and transportation sectors. The Utility's compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility's customers other than large natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligations. The federal administration of President Trump has led to uncertainty with regard to what further actions may occur regarding climate change at the federal level.