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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended
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Dec. 31, 2024
Accounting Policies [Abstract] |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records as regulatory assets costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off. Segment Reporting PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker is the Chief Executive Officer of PG&E Corporation. Net income (loss) is the measure that the chief operating decision maker uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Consolidated Financial Statements. PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information. 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. Cash equivalents are stated at fair value. As of December 31, 2024 and 2023, the Utility also held $272 million and $294 million of Restricted cash and restricted cash equivalents, respectively, 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, 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. Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in Accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass through to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer:
| Year Ended December 31,
(in millions) | 2024 |  | 2023 |  | 2022
Electric |  |  |  |  |
Revenue from contracts with customers |  |  |  |  |
Residential | $ | 7,504 |  |  | $ | 6,041 |  |  | $ | 6,130 |
Commercial | 7,201 |  |  | 5,643 |  |  | 5,416 |
Industrial | 2,065 |  |  | 1,784 |  |  | 1,626 |
Agricultural | 1,815 |  |  | 1,413 |  |  | 1,830 |
Public street and highway lighting | 103 |  |  | 83 |  |  | 77 |
Other, net (1) | (47) |  |  | 136 |  |  | (247) |
Total revenue from contracts with customers - electric | 18,641 |  |  | 15,100 |  |  | 14,832 |
Regulatory balancing accounts (2) | (830) |  |  | 2,324 |  |  | 228 |
Total electric operating revenue | $ | 17,811 |  |  | $ | 17,424 |  |  | $ | 15,060 |
Natural gas |  |  |  |  |
Revenue from contracts with customers |  |  |  |  |
Residential | $ | 3,089 |  |  | $ | 3,686 |  |  | $ | 3,353 |
Commercial | 984 |  |  | 1,052 |  |  | 1,005 |
Transportation service only | 1,815 |  |  | 1,603 |  |  | 1,534 |
Other, net (1) | 159 |  |  | (145) |  |  | 163 |
Total revenue from contracts with customers - gas | 6,047 |  |  | 6,196 |  |  | 6,055 |
Regulatory balancing accounts (2) | 561 |  |  | 808 |  |  | 565 |
Total natural gas operating revenue | 6,608 |  |  | 7,004 |  |  | 6,620 |
Total operating revenues | $ | 24,419 |  |  | $ | 24,428 |  |  | $ | 21,680 |
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent alternative revenues authorized to be billed or refunded to customers. Financial Assets Measured at Amortized Cost – Credit Losses PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2024, PG&E Corporation and the Utility identified the following significant categories of financial assets. Trade Receivables Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses. Expected credit losses of $341 million, $636 million, and $143 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2024, 2023, and 2022, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively. As of December 31, 2023, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $507 million and $78 million, respectively. The RUBA current balancing account balance decreased from December 31, 2023 to December 31, 2024 primarily due to a decrease in under-collections from residential customers in 2024, which are expected to be recovered in 2025. Other Receivables and Available-For-Sale Debt Securities Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss. As of December 31, 2024, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in Current assets – Other and Other noncurrent assets – Other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. Inventories Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or for use as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” below. The Utility’s estimated service lives of its property, plant, and equipment were as follows:
| Estimated Service |  | Balance at December 31,
(in millions, except estimated service lives) | Lives (years) |  | 2024 |  | 2023
Electricity generating facilities (1) | 1 to 75 |  | $ | 11,420 |  |  | $ | 11,423 |
Electricity distribution facilities | 10 to 70 |  | 49,821 |  |  | 45,205 |
Electricity transmission facilities | 15 to 75 |  | 18,481 |  |  | 17,562 |
Natural gas distribution facilities | 15 to 60 |  | 17,213 |  |  | 16,324 |
Natural gas transmission and storage facilities | 15 to 68 |  | 11,117 |  |  | 10,496 |
General plant and other | 5 to 50 |  | 10,210 |  |  | 9,165 |
Financing lease |  |  | 814 |  |  | 787 |
Construction work in progress |  |  | 4,458 |  |  | 4,452 |
Total property, plant, and equipment |  |  | 123,534 |  |  | 115,414 |
Accumulated depreciation |  |  | (35,304) |  |  | (33,093) |
Net property, plant, and equipment (2) |  |  | $ | 88,230 |  |  | $ | 82,321 |
(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below. Nuclear generating facilities have been authorized by the CPUC to be fully depreciated by December 31, 2025. (2) Includes $3.0 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and in a pattern consistent with principal payments. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.61% in 2024, 3.56% in 2023, and 3.74% in 2022. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred. Allowance for Funds Used During Construction AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $111 million and $184 million during 2024, $82 million and $179 million during 2023, and $81 million and $184 million during 2022. Asset Retirement Obligations The following table summarizes the changes in ARO during 2024 and 2023, including nuclear decommissioning obligations:
(in millions) | 2024 |  | 2023
ARO liability at beginning of year | $ | 5,512 |  |  | $ | 5,912 |
Revision in estimated cash flows | (290) |  |  | (585) |
Accretion | 269 |  |  | 253 |
Liabilities settled | (47) |  |  | (68) |
ARO liability at end of year | $ | 5,444 |  |  | $ | 5,512 |
PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below. The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and estimated decommissioning dates. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed cost studies of its nuclear generation facilities in conjunction with the NDCTP, most recently performed in 2021, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plant. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs through rates using a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2024 and December 31, 2023 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2024, the Utility recorded a $222 million reduction to the nuclear decommissioning ARO to reflect the NRC’s decision to grant DCPP’s extended operations until 2030. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals. Disallowance of Plant Costs PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at DCPP and the Humboldt Bay independent spent fuel storage installation. Nuclear decommissioning requires the safe removal of a nuclear generation facility 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. The Utility’s nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC. Gains or losses on the nuclear decommissioning trust investments are refundable to or recoverable from, respectively, customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. Government Assistance The Utility participated in various government assistance programs during the years ended December 31, 2024, 2023, and 2022. The Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance. Assembly Bill 180 On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. DWR Loan Agreement On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for DCPP Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of DCPP. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility received the final proceeds from the DWR loan agreement in 2024. For more information, see the DWR loan activity table below. The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred. The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:
(in millions) |  | 2024 |  | 2023 |  | 2022
Long-term debt: |  |  |  |  |  |
Beginning Balance - DWR loan outstanding |  | $ | 98 |  |  | $ | 312 |  |  | $ | — |
Proceeds received |  | 980 |  |  | — |  |  | 350 |
Operating Expenses: |  |  |  |  |  |
Operating and maintenance expense - Performance-based disbursements |  | (117) |  |  | (124) |  |  | (38) |
Operating and maintenance expense - Loan forgiveness and other adjustments |  | (75) |  |  | (90) |  |  | — |
Long-term debt: |  |  |  |  |  |
Ending Balance - DWR loan outstanding |  | $ | 886 |  |  | $ | 98 |  |  | $ | 312 |
U.S. DOE’s Civil Nuclear Credit Program On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $265 million and $115 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the years ended December 31, 2024 and 2023, the Consolidated Statements of Income reflected $138 million and $76 million, as a deduction to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIEs Receivables Securitization Program The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Consolidated Balance Sheets. The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2024 and December 31, 2023, the SPV had net accounts receivable of $3.2 billion and $2.7 billion, respectively, and outstanding borrowings of zero and $1.5 billion respectively, under the Receivables Securitization Program. For more information, see Note 4 below. AB 1054 Securitization PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate Recovery Property. PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Recovery Funding LLC had outstanding borrowings of $3.2 billion and $1.8 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. SB 901 Securitization PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property. PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the year ended December 31, 2024 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of December 31, 2024 and December 31, 2023, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.2 billion and $7.3 billion respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below. Non-Consolidated VIEs Power Purchase Agreement s Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of December 31, 2024, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of December 31, 2024, it did not consolidate any of them. The Lakeside Building BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building, which serves as the Utility’s principal administrative headquarters. BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property, and the Utility does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to an issued letter of credit, base rent, and certain costs it pays according to the office lease agreement. As a result, the Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC. For more information, see “Oakland Headquarters Lease and Purchase” in Note 15 below. Contributions to the Wildfire Fund Established Pursuant to AB 1054 PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing ratably over the life of the fund based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. AB 1054 did not specify a period of coverage for the Wildfire Fund, and so this accounting treatment is subject to significant accounting judgments and estim ates. In esti mating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund. PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required when additional information becomes available. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility initially estimated a period of coverage of 15 years. In the first quarter of 2024, the annual assessment resulted in the expected life of the Wildfire Fund increasing to 20 years after incorporating 2023 loss information into the dataset with no new events triggering a claim against the Wildfire Fund. PG&E Corporation and the Utility also assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that claims are made from the Wildfire Fund for catastrophic wildfires. 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 year 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 applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Consolidated Statements of Income. For more information, see “Wildfire Fund under AB 1054” in Note 14 below. Other Accounting Policies For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, “Wildfire-Related Contingencies” in Note 14, and “Other Contingencies and Commitments” in Note 15 below. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2024 consisted of the following:
(in millions, net of income tax) | Pension Benefits |  | Other Benefits |  | Available-for-Sale Securities(2) |  | Total
Beginning balance | $ | (28) |  |  | $ | 18 |  |  | $ | 2 |  |  | $ | (8) |
Other comprehensive income before reclassifications: |  |  |  |  |  |  |
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively) | — |  |  | — |  |  | 1 |  |  | 1 |
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively) | (268) |  |  | 29 |  |  | — |  |  | (239) |
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively) | 260 |  |  | (29) |  |  | — |  |  | 231 |
Amounts reclassified from other comprehensive income: |  |  |  |  |  |  |
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1) | (2) |  |  | 2 |  |  | — |  |  | — |
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively) (1) | 1 |  |  | (16) |  |  | — |  |  | (15) |
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1) | 2 |  |  | 14 |  |  | — |  |  | 16 |
Net current period other comprehensive income | (7) |  |  | — |  |  | 1 |  |  | (6) |
Ending balance | $ | (35) |  |  | $ | 18 |  |  | $ | 3 |  |  | $ | (14) |
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 12 below for additional details. (2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC. The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2023 consisted of the following:
(in millions, net of income tax) | Pension Benefits |  | Other Benefits |  | Customer Credit Trust |  | Total
Beginning balance | $ | (12) |  |  | $ | 18 |  |  | $ | (6) |  |  | $ | — |
Other comprehensive income before reclassifications: |  |  |  |  |  |  |
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively) | — |  |  | — |  |  | 8 |  |  | 8 |
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively) | (196) |  |  | 73 |  |  | — |  |  | (123) |
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively) | 180 |  |  | (73) |  |  | — |  |  | 107 |
Amounts reclassified from other comprehensive income: |  |  |  |  |  |  |
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1) | (3) |  |  | 2 |  |  | — |  |  | (1) |
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively)(1) | 1 |  |  | (14) |  |  | — |  |  | (13) |
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1) | 2 |  |  | 12 |  |  | — |  |  | 14 |
Net current period other comprehensive income (loss) | (16) |  |  | — |  |  | 8 |  |  | (8) |
Ending balance | $ | (28) |  |  | $ | 18 |  |  | $ | 2 |  |  | $ | (8) |
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 12 below for additional details. Recognition of Lease Assets and Liabilities A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless it can ascertain an implicit discount rate from the leasing arrangement. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense as paid in conformity with ratemaking. Financing Leases Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024 and 2023, the Utility made total fixed cash payments of $315 million and $142 million, respectively, for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Financing leases were immaterial for the year ended December 31, 2022. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s financing lease ROU assets and lease liabilities relate to the Oakland Headquarters lease discussed below. Oakland Headquarters Lease and Purchase On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million. The term of the Lease began on April 8, 2022. The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2024, the Landlord has made available approximately 715,000 rentable square feet of the leased premises for the Utility’s use. On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the legal parcel that contains the Lakeside Building (the “Property”), as modified. Pursuant to the Agreement of Purchase and Sale and Joint Escrow Instructions, the purchase price of the Property will be $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million paid by July 11, 2024, and the remaining $506 million to be paid at closing on or before June 3, 2025. The Utility will also receive a credit of approximately $172 million towards the final payment, subject to adjustments, which represents the estimated outstanding principal balance of a loan carried by the Property that will be assigned to, and assumed by, the Utility at closing. The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing. The execution of the Amendment to Office Lease Agreement on July 11, 2023 triggered a modification of the Lease, which resulted in the Lease being remeasured and reclassified from an operating lease to a financing lease during the year ended 2023. As of December 31, 2024, the Utility has recorded $807 million in Financing lease ROU assets, $282 million in accumulated amortization, $136 million in leasehold improvements, net of accumulated amortization, which includes $51 million that was provided to the Utility as lease incentives, and $575 million in current Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended. As of December 31, 2023, the Utility recorded $787 million in Financing lease ROU assets, $108 million in accumulated amortization, $218 million in leasehold improvements, net of accumulated amortization, which includes $134 million that was provided to the Utility as lease incentives, $259 million in current Financing lease liabilities, and $554 million in noncurrent Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended. At December 31, 2024 and 2023, the Utility’s financing lease had a weighted average remaining lease term of 0.5 years and 1.6 years and a weighted average discount rate of 6.2% and 6.5%, respectively. The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
| Year Ended December 31,
(in millions) | 2024 |  | 2023 |
Financing lease fixed cost: |  |  |  |
Amortization of ROU assets | $ | 274 |  |  | $ | 115 |  |
Interest on lease liabilities | 42 |  |  | 27 |  |
Financing lease variable cost | 9 |  |  | 3 |  |
Total financing lease costs | $ | 325 |  |  | $ | 145 |  |
At December 31, 2024, the Utility expects to pay $591 million of lease payments in 2025. Operating Leases Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2024, 2023, and 2022, the Utility made total cash payments, including fixed and variable, of $1.6 billion, $1.9 billion, and $2.3 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. At December 31, 2024 and 2023, the Utility’s operating leases had a weighted average remaining lease term of 7.5 years and 8.2 years and a weighted average discount rate of 6.5% and 6.4%, respectively. The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
| Year Ended December 31,
(in millions) | 2024 |  | 2023 |  | 2022
Operating lease fixed cost | $ | 116 |  |  | $ | 269 |  |  | $ | 500 |
Operating lease variable cost | 1,524 |  |  | 1,632 |  |  | 1,829 |
Total operating lease costs | $ | 1,640 |  |  | $ | 1,901 |  |  | $ | 2,329 |
At December 31, 2024, the Utility’s future expected operating lease payments were as follows:
(in millions) | December 31, 2024
2025 | $ | 116 |
2026 | 112 |
2027 | 110 |
2028 | 97 |
2029 | 62 |
Thereafter | 195 |
Total lease payments | 692 |
Less imputed interest | (173) |
Total | $ | 519 |
Recently Adopted Accounting Standards Segment Reporting In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amended the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. PG&E Corporation and the Utility adopted this ASU in December 2024. See “Segment Reporting” above for additional disclosures as a result of adopting this ASU. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU. Accounting Standards Issued But Not Yet Adopted Income Taxes In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and income taxes paid disaggregated by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. PG&E Corporation and the Utility do not expect the guidance to have a significant impact on their Consolidated Financial Statements and related disclosures. Disaggregation of Income Statement Expenses In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures. Induced Conversions of Convertible Debt Instruments In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

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