PG&E Corp

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following applications.

During year ended December 31, 2023 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

•In February 2024, the CPUC issued a final resolution approving an Administrative Consent Order and Agreement between the SED and the Utility regarding the 2021 Dixie fire.

•In December 2023, the NRC deemed the Utility’s application for license renewal sufficient, which allows continued operations at Diablo Canyon past the plant’s current licenses, and the CPUC approved extended operations at Diablo Canyon.

•In December 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP, which the CPUC ratified in February 2024. The OEIS issued a safety certificate for the Utility in January 2024.

•In December 2023, the CPUC approved the Utility’s advice letter indicating that the cost of capital adjustment mechanism had been triggered and increased the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%.

•In November 2023, the CPUC issued a final decision in the Utility’s 2023 GRC, which authorized the Utility’s base revenues for the period of 2023 through 2026. For 2023, the revenue requirement was $13.52 billion, excluding self-insurance.

•Since January 2023, the Utility has filed cost recovery applications requesting aggregate cost recovery of approximately $4.7 billion of recorded expenditures. In terms of interim rate relief, the CPUC has issued a PD for $516 million and a final decision for $1.1 billion. In terms of final cost recovery, the CPUC has authorized aggregate revenue requirements of $1.76 billion, which does not include costs that remain to be addressed.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

(1) The revenue requirement request amounts do not include interest.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts.

On August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023. The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

2022 WMCE Application

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility’s interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

On December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.

On June 23, 2023, the ALJ revised the procedural schedule to indicate that a PD would be issued by the second quarter of 2024.

2023 WMCE Application

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

In connection with the 2023 WMCE application, the Utility also requested interim rate relief of $1.46 billion to be recovered over 12 months beginning March 1, 2024. The remaining $399 million would be recovered after the CPUC issues a final decision. On January 29, 2024, the Utility filed a supplemental motion for interim rate relief based on an agreement with the Public Advocates Office of the CPUC. Under the supplemental motion, the Utility would recover $944 million over 17 months, at least $500 million of which would be recovered in 2024. Following the 17-month period, the Utility would recover the remaining $515 million amount up to $1.46 billion.

The Utility has requested a final decision in the proceeding by the end of 2024 or, if the supplemental motion for interim rate relief is granted, the second quarter of 2025.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:

In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On February 1, 2024, the CPUC issued a PD that would authorize the Utility to recover $516 million in interim rates to be recovered over 12 months.

The ALJ has adopted a schedule that would result in a final decision on the wildfire mitigation costs by November 2024 and a final decision on the gas safety and electric modernization costs by June 2025.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS and the CPUC approve guidelines (see “SB 884 10-Year Distribution Undergrounding Program” below).

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

2023 General Rate Case

Phase 1

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC. The 2023 GRC combined what had historically been separated into the GRC and GT&S. In the 2023 GRC, the CPUC determined the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 (the “GRC period”) to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Between August 2021 and December 2022, the Utility served various updates to its 2023 GRC testimony.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

On November 17, 2023, the CPUC issued a final decision on Phase 1, Tracks 1 and 2.

Track 1

The Utility is authorized to collect through rates the approved revenue requirement increases beginning January 1, 2024 and to amortize the incremental revenue increases related to 2023 for 24 months over the period of January 1, 2024 through December 31, 2025.

The following table compares the Track 1 revenue requirements authorized in the final decision with the revenue requirement authorized for 2022 in the 2020 GRC and 2019 GT&S proceedings and the revenue requirement requested in the Utility’s application as amended and updated:

(1) Request has been adjusted to exclude amounts related to self-insurance.

The final decision also grants 50% of the Utility’s requested increase in escalation rates.

Track 2

On July 22, 2022, the Utility submitted a request for Track 2 of the GRC proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $209 million in expenses and $129 million in capital expenditures. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

The final decision approved the settlement agreement in Track 2 of the proceeding. The settlement agreement results in a revenue requirement of $221 million to be recovered over 2023 and 2024.

Rate Base and Capital Additions

The following table compares the weighted-average GRC rate base that the final decision authorizes with the weighted-average GRC rate base requested in the Utility’s application as amended and updated:

The final decision authorizes funding for 1,230 miles of undergrounding and 778 miles of covered conductor for the GRC period. The Utility most recently had requested 2,000 miles of undergrounding and 320 miles of covered conductor for the GRC period.

The final decision denies cost recovery through this GRC for a number of costs but gives the Utility an opportunity to seek recovery of these costs in future proceedings to the extent they are eligible for cost recovery: capital costs of $0.9 billion associated with moving the Utility’s corporate headquarters to Oakland, California; capital costs of $1.2 billion for rebuilding electric and gas infrastructure following the 2018 Camp fire; capital costs of $1.3 billion tracked in certain wildfire mitigation and other memorandum accounts; and capital costs of $0.7 billion for the gas advanced metering infrastructure module replacement project. These costs and the corresponding rate base have been removed from the final decision.

Additional Capacity Phase

On September 15, 2023, the Utility served opening testimony proposing to establish a balancing account consistent with SB 410 to record and recover costs of electric distribution capacity additions and new non-residential electric distribution extension work incremental to the forecasts of the Utility’s Phase 1 2023 GRC. The Utility proposed to record to the balancing account actual capital expenditures for these programs, with recorded costs for a given year to be recovered through the following year’s rates and subject to reasonableness review in the 2027 GRC application. Costs recorded to the account would be subject to an annual cap, which is designed to effectuate an electric distribution average rate impact of no more than 2.5%, calculated based on the Utility’s adopted GRC electric distribution revenue requirement for the applicable year beginning in 2024. Based on the final decision on Phase 1, the cap would equate to approximately $183 million of revenue requirement and incremental capital expenditures of approximately $1.26 billion. A PD on the balancing account proposal is expected in the second quarter of 2024.

Cost of Capital Proceedings

2023 Cost of Capital Application

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital including ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision. On December 14, 2023, certain intervenors filed a petition for modification requesting that the 2023 Cost of Capital decision be modified to, among other things, suspend application of the cost of capital adjustment mechanism pending further CPUC decision. On January 16, 2024, the Utility submitted its response.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding. On September 20, 2023, the assigned ALJ issued a ruling identifying the remaining issues to be addressed in the second phase of the proceeding and outlining a proposed process and schedule to resolve the remaining issues.

Cost of Capital Adjustment Mechanism

On October 13, 2023, the Utility filed an advice letter indicating that the cost of capital adjustment mechanism had been triggered and requesting to increase the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%. On December 22, 2023, the CPUC approved the Utility’s advice letter. As a result, the Utility is authorized to collect a revenue requirement of $328 million, based on the 2023 GRC rate base, effective January 1, 2024. On January 12, 2024, several intervenors submitted a request for the CPUC to review the approval.

The Utility’s annual cost of capital adjustment mechanism provides that in any year during the applicable cost of capital period in which the difference between (i) the average Moody’s Baa utility bond rates (as measured in the 12-month period from October of the prior year through September of the year in which the mechanism could trigger (the “Index”)) and (ii) 4.37% (based on the 2023 Cost of Capital decision) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism is triggered, to become effective on January 1 of the next year. For the period from October 1, 2022 to September 30, 2023, the Index averaged 141 basis points above the Utility’s cost of capital benchmark rate of 4.37%, triggering the adjustment mechanism for the rest of the Cost of Capital period. Starting on January 1, 2024, the Utility’s authorized ROE increased from 10.0% to 10.7%, its authorized cost of long-term debt increased from 4.31% to 4.66%, and the benchmark has been updated to 5.78%.

Transmission Owner Rate Cases

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

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasts a 2024 retail electric transmission revenue requirement of $2.83 billion. The proposed amount reflects an approximately 11% decrease over the current rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above). The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. The Utility has requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO. The TO21 filing also addresses the Utility’s capital structure and several new issues including wildfire self-insurance recovery from transmission customers. On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but rejecting the 0.5% ROE adder for participation in the CAISO. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s rejection of the 0.5% ROE adder.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 26, 2023, the OEIS issued its final Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the final ARC, the OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets, but did not substantially comply with the WMP during the 2020 compliance period. On March 24, 2023, the Utility filed a writ in the California superior court seeking judicial review of the OEIS ARC on the grounds that the OEIS failed to utilize the compliance evaluation criteria adopted by the CPUC. If the court sustains the ARC’s finding that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate whether they will incur a loss in connection with the ARC or the amount of any such loss, as the writ is pending in state court and because any penalty issued by the CPUC depends upon various factors.

2023-2025 Wildfire Mitigation Plan

On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events. On June 22, 2023, the OEIS issued a revision notice requiring the Utility to address eight critical issues. The Utility submitted the response to the revision notice on August 7, 2023. On September 27, 2023, the Utility submitted additional information on the revision notice response to the OEIS. On December 29, 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP. On February 15, 2024, the CPUC ratified the OEIS’s approval.

The Utility expects to submit updates to the WMP for 2025 on April 1, 2024, as directed by the OEIS.

OIR to Revisit Net Energy Metering Tariffs

On December 19, 2022, the CPUC issued a final decision in the rulemaking proceeding to develop a successor to the NEM tariffs. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, deferred this issue to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for residential electric customers. The decision does, however, clarify that fixed charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On June 30, 2023, the CPUC denied the application.

On May 4, 2023, intervenors filed in the California Court of Appeal a petition for writ of review of the CPUC’s decision. On December 20, 2023, the appellate court affirmed the CPUC’s decision.

Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter.

On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving the transfer of FERC-jurisdictional assets from the Utility to Pacific Generation.

Self-Reports to the CPUC

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. For more information about the EOEP, see “PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process” in Item 1A. Risk Factors. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022 and February 1, 2024, the Utility submitted updates to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures.

The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Extension of Diablo Canyon Operations

On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility would continue to operate Diablo Canyon on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs would be responsible for the cost of extended operations.

The key steps to continued operations are NRC license renewal and approvals from California state agencies, including the CPUC, CEC, California State Lands Commission, California Coastal Commission, and other state agencies. As set forth below, many of these approvals have been received, but if any such approval is not received, the Utility would retire Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC.

On February 28, 2023, and in consultation with the CAISO and CPUC, the CEC determined that it is prudent to extend the operation of Diablo Canyon to support electric system reliability through 2030.

The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with Diablo Canyon. On June 5, 2023, the California State Lands Commission approved an extension of the Utility’s lease at Diablo Canyon through October 31, 2030.

On August 15, 2023, the California State Water Resources Control Board approved the Utility’s plan for once-through cooling at Diablo Canyon.

On September 26, 2023 the CEC issued a draft report concluding that no suitable supply-side resources can be brought online as alternatives to Diablo Canyon’s energy and capacity output prior to the planned retirement dates in 2024 and 2025.

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On December 19, 2023, the NRC deemed the application sufficient, which allows continued operations at Diablo Canyon past the plant’s current licenses.

On December 14, 2023, the CPUC approved extended operations at Diablo Canyon until October 31, 2029 for Unit 1 and October 31, 2030 for Unit 2. The approval is subject to the following conditions: (1) the NRC continues to authorize Diablo Canyon operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that Diablo Canyon extended operations are imprudent or unreasonable.

Application for Third AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge.

On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the first quarter of 2024, which it subsequently extended through the second quarter of 2024. The $1.38 billion reflected $187 million of recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts approved in the 2023 GRC. These amounts were not included in the first or second securitization transactions. The final amount to be financed using securitization would be based on actual recorded and authorized capital expenditures incurred by the Utility prior to the securitization transaction and not to exceed the remaining $1.38 billion of the Utility’s AB 1054 allocation. If approved, the Utility anticipates the transaction will result in the last securitization of AB 1054 capital expenditure amounts subject to the equity rate base exclusion.

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds. The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds.

The Utility has requested a financing order to be issued within 180 days after the filing of the application on August 10, 2023. On November 22, 2023, the Utility filed opening briefs to update the capital expenditures forecast for the 2023 GRC final decision and extend the forecast capex period through the second quarter of 2024. On February 15, 2024, the CPUC issued a final decision approving the Utility’s application.

SB 884 10-Year Distribution Undergrounding Program

On November 9, 2023, the Safety and Policy Division of the CPUC issued a resolution which, if adopted, would establish an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC's review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. The draft resolution is currently on the CPUC’s March 7, 2024 meeting agenda.

On December 13, 2023, the OEIS issued a request for comments as part of its ongoing process to develop guidelines for its program. The Utility and other stakeholders submitted comments on January 8, 2024 and reply comments on January 18, 2024.

The Utility anticipates that the OEIS and the CPUC will issue final guidelines in early 2024. The Utility expects to submit its undergrounding plan to the OEIS in mid-2024 before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.