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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended
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Dec. 31, 2022
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. Cash, Cash Equivalents, and Restricted Cash Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. 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 on 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) | 2022 |  | 2021
Electric |  |  |
Revenue from contracts with customers |  |  |
Residential | $ | 6,130 |  |  | $ | 6,089 |
Commercial | 5,416 |  |  | 5,042 |
Industrial | 1,626 |  |  | 1,493 |
Agricultural | 1,830 |  |  | 1,565 |
Public street and highway lighting | 77 |  |  | 73 |
Other, net (1) | (247) |  |  | (84) |
Total revenue from contracts with customers - electric | 14,832 |  |  | 14,178 |
Regulatory balancing accounts (2) | 228 |  |  | 953 |
Total electric operating revenue | $ | 15,060 |  |  | $ | 15,131 |
Natural gas |  |  |
Revenue from contracts with customers |  |  |
Residential | $ | 3,353 |  |  | $ | 2,759 |
Commercial | 1,005 |  |  | 713 |
Transportation service only | 1,534 |  |  | 1,346 |
Other, net (1) | 163 |  |  | 140 |
Total revenue from contracts with customers - gas | 6,055 |  |  | 4,958 |
Regulatory balancing accounts (2) | 565 |  |  | 553 |
Total natural gas operating revenue | 6,620 |  |  | 5,511 |
Total operating revenues | $ | 21,680 |  |  | $ | 20,642 |
(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 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, 2022, 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. As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022. PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively. 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 and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, 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, 2022, 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 to be used 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 AFUDC. See “AFUDC” 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) |  | 2022 |  | 2021
Electricity generating facilities (1) | 5 to 75 |  | $ | 11,781 |  |  | $ | 11,217 |
Electricity distribution facilities | 10 to 70 |  | 41,061 |  |  | 37,723 |
Electricity transmission facilities | 15 to 75 |  | 16,413 |  |  | 15,516 |
Natural gas distribution facilities | 20 to 60 |  | 15,366 |  |  | 14,100 |
Natural gas transmission and storage facilities | 5 to 66 |  | 9,859 |  |  | 9,067 |
Financing lease |  |  | 18 |  |  | 18 |
Construction work in progress |  |  | 4,137 |  |  | 3,480 |
General plant and other | 5 to 50 |  | 8,518 |  |  | 7,838 |
Total property, plant, and equipment |  |  | 107,153 |  |  | 98,959 |
Accumulated depreciation |  |  | (30,946) |  |  | (29,131) |
Net property, plant, and equipment (2) |  |  | $ | 76,207 |  |  | $ | 69,828 |
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is 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 16 below. (2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below. 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 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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020. 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. AFUDC 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 $81 million and $184 million during 2022, $56 million and $133 million during 2021, and $35 million and $140 million during 2020. Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations:
(in millions) | 2022 |  | 2021
ARO liability at beginning of year | $ | 5,298 |  |  | $ | 6,412 |
Liabilities incurred | 134 |  |  | — |
Revision in estimated cash flows | 325 |  |  | (1,378) |
Accretion | 213 |  |  | 287 |
Liabilities settled | (58) |  |  | (23) |
ARO liability at end of year | $ | 5,912 |  |  | $ | 5,298 |
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 4 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 the estimated date of decommissioning. 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 studies of its nuclear generation facilities every three years in conjunction with the NDCTP, 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 plants. 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 through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals. The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020. The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022. 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 Diablo Canyon and one retired facility at Humboldt Bay. 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. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. 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 PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and 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, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, 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. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred. Senate Bill 846 On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances. DWR Loan Agreement On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, 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 will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements. U.S. DOE’s Civil Nuclear Credit Program On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be 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 actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. 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 will recognize such funding as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense on the Consolidated Statements of Income as eligible costs are incurred. 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, respectively, 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 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 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 order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the 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 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, 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. 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 SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the 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 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below. Non-Consolidated VIEs 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, 2022, it 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, 2022, it did not consolidate any of them. 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 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. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating 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 amount 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. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund. PG&E Corporation and the Utility evaluate and, where appropriate, update all assumptions quarterly. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire. During the year ended December 31, 2022, PG&E Corporation and the Utility updated assumptions related to the mitigation effectiveness and historical fire loss dataset to align with the risk modeling within the 2022 WMP. These updates did not change the estimated period of coverage, which continues to be 15 years from the inception of the Wildfire Fund. As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in Current assets - Wildfire Fund asset, and $4.8 billion in Non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. As of December 31, 2022, PG&E Corporation and the Utility had recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire. For more information, see “Wildfire Fund under AB 1054” in Note 15 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 10, “Derivatives” in Note 11, “Fair Value Measurements” in Note 12, and “Contingencies and Commitments” in Notes 15 and 16 below. Voluntary Separation Program In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income. 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, 2022 consisted of the following:
(in millions, net of income tax) | Pension Benefits |  | Other Benefits |  | Customer Credit Trust |  | Total
Beginning balance | $ | (33) |  |  | $ | 18 |  |  | $ | — |  |  | $ | (15) |
Other comprehensive income before reclassifications: |  |  |  |  |  |  |
Loss on investments (net of taxes of $0, $0 and $3, respectively) | — |  |  | — |  |  | (6) |  |  | (6) |
Unrecognized net actuarial gain (net of taxes of $102, $99 and $0, respectively) | 263 |  |  | (255) |  |  | — |  |  | 8 |
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively) | (242) |  |  | 255 |  |  | — |  |  | 13 |
Amounts reclassified from other comprehensive income: |  |  |  |  |  |  |
Amortization of prior service cost (net of taxes of $1, $2 and $0, respectively) (1) | (3) |  |  | 5 |  |  | — |  |  | 2 |
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively) (1) | 1 |  |  | (29) |  |  | — |  |  | (28) |
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1) | 2 |  |  | 24 |  |  | — |  |  | 26 |
Net current period other comprehensive income (loss) | 21 |  |  | — |  |  | (6) |  |  | 15 |
Ending balance | $ | (12) |  |  | $ | 18 |  |  | $ | (6) |  |  | $ | — |
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 13 below for additional details. The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2021 consisted of the following:
(in millions, net of income tax) | Pension Benefits |  | Other Benefits |  | Total
Beginning balance | $ | (39) |  |  | $ | 17 |  |  | $ | (22) |
Other comprehensive income before reclassifications: |  |  |  |  |
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively) | 1,007 |  |  | 137 |  |  | 1,144 |
Regulatory account transfer (net of taxes of $390 and $53, respectively) | (1,003) |  |  | (136) |  |  | (1,139) |
Amounts reclassified from other comprehensive income: |  |  |  |  |
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) | (4) |  |  | 10 |  |  | 6 |
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively)(1) | 4 |  |  | (24) |  |  | (20) |
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1) | 2 |  |  | 14 |  |  | 16 |
Net current period other comprehensive income | 6 |  |  | 1 |  |  | 7 |
Ending balance | $ | (33) |  |  | $ | 18 |  |  | $ | (15) |
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 13 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 the implicit discount rate in the leasing arrangement can be ascertained. 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 in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2022 and 2021. For the years ended December 31, 2022 and 2021, the Utility made total cash payments, including fixed and variable, of $2.3 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. 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 ROU assets and lease liabilities relate to various power purchase agreements and the Oakland lease. 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 16 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. Property arrangements primarily consist of an office lease agreement for the Lakeside Building. 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 term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes. The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). On February 6, 2023, the process of subdividing the real estate was completed. If the option is exercised pursuant to the terms of the existing agreement then the Purchase Price would be paid in or around July 2023. The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2022, approximately 488,000 rentable square feet of the leased premises has been made available for use by the Utility. The Utility has recorded approximately $535 million in Operating lease right of use assets, approximately $214 million of leasehold improvements, which includes approximately $137 million that was provided to the Utility as lease incentives, and approximately $672 million in noncurrent Operating lease liabilities in the Consolidated Financial Statements related to the Lease. In January 2023, approximately 110,000 of additional rentable square feet was made available for use by the Utility. At December 31, 2022 and 2021, the Utility’s operating leases had a weighted average remaining lease term of 19.6 years and 6.04 years and a weighted average discount rate of 6.5% and 6.1%, respectively. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
| Year Ended December 31,
(in millions) | 2022 |  | 2021
Operating lease fixed cost | $ | 500 |  |  | $ | 578 |
Operating lease variable cost | 1,829 |  |  | 1,782 |
Total operating lease costs | $ | 2,329 |  |  | $ | 2,360 |
At December 31, 2022, the Utility’s future expected operating lease payments were as follows:
(in millions) | December 31, 2022
2023 | $ | 307 |
2024 | 150 |
2025 | 146 |
2026 | 143 |
2027 | 142 |
Thereafter | 2,196 |
Total lease payments | 3,084 |
Less imputed interest | (1,610) |
Total | $ | 1,474 |
Recently Adopted Accounting Standards Debt In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU. Reference Rate Reform On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

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