PG&E Corp
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ITEM 1. BUSINESS
PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in Northern and Central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility’s service area is shown in the graphic below.
PG&E Corporation’s and the Utility’s operating revenues, income, and total assets for the most recently completed year can be found below in Item 8. Financial Statements and Supplementary Data.
The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.
This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. PG&E Corporation and the Utility are separate entities.
Triple Bottom Line
PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the difficulties many employees face in their day-to-day work, and deliver better outcomes for customers and communities.
PG&E Corporation and the Utility measure their progress toward this purpose by considering their impact on the “triple bottom line” of people, planet, and prosperity, which is underpinned by performance; this consideration takes into account not only the economic value they create for customers and investors, but also their responsibility to social and environmental goals. The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities.
PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions. The Utility will continue to seek fair and timely regulatory treatment to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world-class performance while delivering hometown service.
People
The people element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders.
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PG&E Corporation’s and the Utility’s goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe. Their focus is on continuously building an organization where every work activity is designed to facilitate safe performance, every worker knows and practices safe behaviors, and every individual is encouraged to speak up and stop work if they see unsafe or risky behavior, and has confidence that their concerns and ideas will be heard and pursued. PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction.
PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, and equitably-paid workforce. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas service reliability, and improving customer satisfaction.
For more information, see “Human Capital” below.
Planet
The planet element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to protect and serve the environment. PG&E Corporation and the Utility believe that integrating and managing climate change and other environmental considerations in the companies’ business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, employees, and other stakeholders.
The Utility is adapting to severe and extreme climate-driven natural hazards. To build resilience to these hazards, the Utility is working to systematically integrate forward-looking climate data and tools into its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate change policy in California, and work directly with local governments and communities on adaptation solutions.
PG&E Corporation’s and the Utility’s 2022 Climate Strategy Report, which is available to the public, describes the companies’ climate goals and plans to meet those goals. To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the energy system to accommodate increased vehicle and building electrification, integrate a proliferation of distributed energy resources, and achieve increased utilization of renewable energy combined with investments in the grid and energy storage.
PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, affordable, clean, and resilient energy for their customers. As a result of actions already taken by PG&E Corporation and the Utility, the companies have:
•Helped customers avoid emissions and manage energy costs through robust energy efficiency programs.
•Implemented contracts for more than 4.9 GW of battery energy storage capacity, strengthening California’s grid efficiency and reliability.
•Helped enable the total number of electric vehicles operating in the Utility’s service area to exceed 820,000.
•Brought the total number of interconnected private solar customers to more than 950,000.
•Continued to advance decarbonization initiatives for the Utility’s natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule.
Prosperity
The prosperity element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to meeting their financial objectives and providing economic development opportunities and benefits in the communities they serve. Management believes clean energy should be affordable for and inclusive of all economic backgrounds.
Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs.
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See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.
Generally, differences between forecast costs and actual costs can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. Costs can also decrease due to improved efficiencies or waste elimination.
PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time. All three credit ratings agencies have increased PG&E Corporation’s and the Utility’s issuer credit ratings since 2020.
PG&E Corporation's dividend policy entails consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings (a non-GAAP financial measure) by 2028. For more information, see Note 6 of the Notes to the Consolidated Financial Statements.
Total capital expenditures recorded in 2025 were $13.4 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be $12.4 billion for 2026, $13.4 billion for 2027, $15.4 billion for 2028, $16.3 billion for 2029, and $16.0 billion for 2030. The Utility has identified opportunities for investment in the coming years in addition to its forecast, including investments in transmission for data centers and system investments, transportation electrification capacity, hydroelectric facilities, energy storage, information technology, and automation. The Utility plans to submit a 10-year Electric Undergrounding Plan to the OEIS for review. The Utility will then submit an application requesting conditional approval of the plan’s costs to the CPUC. Some of these investments depend on the Utility’s ability to generate or obtain the cash to support such investments over this period of time. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather, and other unforeseen conditions. Additionally, $2.85 billion of fire risk mitigation capital expenditures will be excluded from the Utility’s equity rate base pursuant to SB 254.
The Utility expects to make additional capital expenditures, the recovery of which will be subject to future regulatory approval. These expenditures include capital expenditures exceeding amounts authorized in the 2023 GRC final decision and expenditures to be included in a later filing or separate applications. These expenditures are expected to be primarily for wildfire mitigation and electrification.
PG&E Corporation and the Utility are committed to building a safe, reliable, sustainable, and climate-resilient energy system at an affordable cost for customers. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements collectively place continuing upward pressure on customer rates. Certain CPUC proceedings could impact different types of customers differently. The Utility has set a goal to increase customer capital investments while also limiting customer bill impacts, including by achieving operating cost savings, seeking efficient financing, and benefiting from electric load growth that reduces other customers’ bills. The Utility plans to meet its cost savings goal through increased efficiencies including waste elimination through the Lean operating system. The Utility expects data centers, electric vehicle adoption, and building electrification to drive load growth. For more information see “Competition” below. The Utility has a number of programs in place to assist low-income customers, such as the CARE program. Under the CARE program, income-qualified customers can receive a monthly discount of 20% or more on their natural gas and electric bill. The Utility has set a goal to limit average annual customer rate increases to 3%.
PG&E Corporation’s and the Utility’s Corporate Sustainability Report, which is available to the public, describes the companies’ progress toward world-class performance measured with the triple bottom line framework.
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Performance: Underpinning the Triple Bottom Line
PG&E Corporation and the Utility use the Lean operating system, which includes five basic “plays”: visual management; operating reviews; problem solving; standard work; and waste elimination. Visual management allows teams to see how they are performing against their most important metrics using real-time data. Teams throughout PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of employees closest to the work with the goals and objectives of the companies. These brief meetings help the Utility identify gaps and quickly develop plans to support the teams performing the work and give the Utility more visibility, control and predictability in its operations. Problem solving involves a structured approach to identifying, containing, analyzing, and solving problems in order to capitalize on opportunities. Standard work reduces costs and increases productivity by establishing a consistent company-wide method for completing a task. Waste elimination, the fifth Lean play, involves identifying and eliminating inefficiencies in both process and workflow in a sustainable manner and driving the continued adoption of consistent processes and improvements to financial visibility and controls.
The Utility has responded to wildfire risk by implementing operational changes and investing in safety, including:
•Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them in less than one-tenth of a second in the event of a disturbance to help prevent potential ignitions. The Utility has enabled EPSS in all high fire risk areas.
•Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions. Since its inception in late 2017, the PSPS program has become more targeted through the use of sectionalizers, which enable more targeted de-energizations, and more granular risk models.
•Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and mitigate vegetation that might grow or fall into utility equipment. Additional inspections are conducted within a subset of HFTD areas. The Utility continues to leverage remote sensing technology to enhance data driven inspection planning and safe work execution.
•Asset inspections: Asset inspections identify equipment conditions before failure. The Utility’s asset inspection programs continue to grow more risk-informed, thorough, standardized, digitized, and verifiable.
•System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTD areas and installing stronger and more resilient equipment. As the Utility’s asset inspections have identified less resilient equipment, the Utility has hardened its system by fixing significantly more equipment than in prior years. Hardening methods also include replacing bare overhead conductors with covered conductors and installing stronger poles, removing lines, serving customers through remote grids, or converting lines from overhead to underground.
In recent years, the Utility has introduced or expanded its use of several measures including clearing defensible space around transmission structures, downed conductor detection, partial voltage force outs, and transmission operational controls which further decreased wildfire ignition risk.
The Utility’s equipment was not involved in the ignition of any major wildfires in 2025. The Utility experienced a decreased number of CPUC-reportable ignitions in 2025, compared to 2024, due to continued operational improvements.
The Utility is also continuing to invest in a safe and reliable gas system. The Utility’s asset safety efforts include pipeline replacements, strength testing, and real-time monitoring systems. Additionally, the Utility educates the public and its workforce regarding safe digging practices and maintains rapid outage response protocols to protect public safety and minimize service disruptions.
The Utility’s generation operations focus on safety, compliance, environmental stewardship, and asset reliability. The Utility focuses on continuous improvement, risk informed decision-making, and adhering to industry standards for asset risk management and lifecycle optimization. Work management systems enable the execution and tracking of preventative and corrective maintenance strategies for generation assets.
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Regulatory Environment
The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. The Utility is regulated primarily at the state level by the CPUC and at the federal level by the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and the OEIS.
This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. For more information, see Item 1A. Risk Factors and “Regulatory Matters” in Item 7. MD&A.
PG&E Corporation is subject to the Public Utility Holding Company Act as a public utility holding company. The Public Utility Holding Company Act primarily obligates PG&E Corporation and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
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Financial statements
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8.
Generally, PG&E Corporation’s and the Utility’s revenues vary based on the outcomes of ratemaking proceedings and the amount of pass-through costs incurred. See “Ratemaking Mechanisms” in Item 1. Description of the Business regarding how the Utility’s revenues are determined. Factors that cause costs to vary include the cost of purchased power and fuel; the costs of procurement storage, transportation of natural gas; weather; criminal, civil and regulatory charges for wildfires; the outcomes of ratemaking proceedings; and increases in interest expense as a result of additional debt issuances.
The discussion related to the results of operations and liquidity for 2024 compared to 2023 is incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC in February 2025.
Key Factors Affecting Financial Results
PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:
•The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, self-insurance, the Wildfire Fund, the Continuation Account, and regulatory recovery.
In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps designed to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, system hardening, situational awareness tools, and ignition response. These initiatives reduce but do not eliminate the Utility’s wildfire risk.
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Despite these extensive measures, the Utility’s equipment may still be involved in the ignition of future wildfires, including catastrophic wildfires. This risk is exacerbated by a variety of factors, including climate change and severe weather events (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), as well as infrastructure and vegetation conditions. Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is determined primarily by environmental and vegetation conditions, third-party suppression efforts, and the location of the wildfire.
PG&E Corporation and the Utility have and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. The Utility could also face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for noncompliance related to wildfire mitigation efforts.
The financial impact of past wildfires is significant. As of December 31, 2025, PG&E Corporation and the Utility have incurred significant liabilities for past wildfires (aggregate liability estimates of $1.325 billion for the 2019 Kincade fire, $2.15 billion for the 2021 Dixie fire, and $350 million for the 2022 Mosquito fire). These estimates do not include all categories of potential damages and losses.
PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage or self-insurance through the Wildfire Fund, the Continuation Account, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund or Continuation Account coverage year (“Coverage Year”), the Wildfire Fund or the Continuation Account, as applicable, may be available to reimburse the Utility such excess amount. The Utility’s ability to recover wildfire costs depends on the Wildfire Fund or the Continuation Account having sufficient remaining funds, and the Wildfire Fund or the Continuation Account may also be depleted more quickly than expected as a result of claims made by California’s other participating electric utility companies. Whether the Utility will be required to reimburse the Wildfire Fund or the Continuation Account depends on its ability to demonstrate to the CPUC that paid wildfire-related costs were just and reasonable.
With respect to the Wildfire Fund, SCE has disclosed that a liability for the wildfire that began on January 7, 2025, in Eaton Canyon in Los Angeles County, California (the “Eaton fire”) is probable but not reasonably estimable. PG&E Corporation and the Utility expect to reduce their 20-year estimated life of the Wildfire Fund and assess the Wildfire Fund asset for accelerated amortization based on reliable, publicly available information, including when and if SCE accrues a liability or a Wildfire Fund receivable, respectively (see Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8).
Recoveries for the 2019 Kincade fire are also subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. The Utility has recorded an aggregate Wildfire Fund receivable of $1.150 billion for the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025.
With respect to the Continuation Account, additional uncertainties include whether the Wildfire Fund administrator determines that the Continuation Account is necessary, whether the CPUC authorizes extending the non-bypassable charge, whether the administrator determines that additional contributions are needed and, if so, the timing of those contingent contributions.
The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover some or all of the expenses that it has recorded as receivables. As of December 31, 2025, the Utility has recorded receivables for regulatory recovery of $632 million for the 2021 Dixie fire and $61 million for the 2022 Mosquito fire. See “2021 Dixie Fire” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8 for more information.
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•The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). Although the Utility generally seeks to recover its recorded costs on a timely basis, greater memorandum and balancing account balances increase the Utility’s financing costs. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8, and “Regulatory Matters” below.
•There has been increased California state legislative activity and political dialogue in recent years regarding wildfires, energy affordability, and related topics. The substance and timing of any legislation or other executive or regulatory measures relating to these matters, if such measures are implemented, could have a material impact on PG&E Corporation’s and the Utility’s business, cash flows, results of operations, and financial condition.
•PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility intends to achieve such savings by improving the planning and execution of its business through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to reduce financing costs by identifying and executing on opportunities to efficiently finance the business, which depend on capital market conditions. Increased volatility in capital markets and continued elevated interest rates may impact PG&E Corporation’s and the Utility’s ability to obtain financing on acceptable terms or raise the cost of financing, which in turn may negatively impact their financial results.
For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ materially from historical results, see Item 1A: “Risk Factors” and “Forward-Looking Statements” above.
Tax Matters
PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $38.3 billion and a California net operating loss carryforward of approximately $34.1 billion as of December 31, 2025.
Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation’s or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate value of stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and PG&E Corporation’s Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022 (the “Amended Articles”), contain restrictions on the direct or indirect acquisition or accumulation of PG&E Corporation’s stock. These restrictions prevent any person or entity (including certain groups of persons) from acquiring or accumulating 4.75% or more of the combined value of PG&E Corporation’s stock, including common stock and mandatory convertible preferred stock prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.
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Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Accordingly, although PG&E Corporation had 2,675,711,544 common shares outstanding as of February 4, 2026, only 2,197,967,954 common shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles with the result that the ownership limitation based on the unadjusted outstanding stock of PG&E Corporation is lower than 4.75% and can vary based on the relative value of the common stock and mandatory convertible preferred stock on any particular date. For example, based on the closing prices of PG&E Corporation’s common stock and preferred stock as of February 4, 2026, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2026 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock. The computation of the Percentage Stock Ownership is complex, and persons considering purchasing PG&E Corporation’s stock should consult their own tax advisors regarding the application of the ownership restrictions to their particular situation.
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.
RESULTS OF OPERATIONS
The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2025 and 2024. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.
PG&E Corporation
The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of income (loss) attributable to common shareholders:
| (in millions) | 2025 | 2024 | Net Change | Percentage Change | ||||||||||||||||
| Consolidated Total | $ | 2,593 | $ | 2,475 | $ | 118 | 5 | % | ||||||||||||
| PG&E Corporation | (472) | (223) | (249) | 112 | % | |||||||||||||||
| Utility | 3,065 | 2,698 | 367 | 14 | % | |||||||||||||||
PG&E Corporation’s net loss primarily consists of interest expense on long-term debt.
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Utility
The table below shows the Utility’s Consolidated Statements of Income for 2025 and 2024. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact Net income. The line items with significant net changes are described below.
| Year Ended December 31, | Net Change (1) | Percentage Change | |||||||||||||||||||
| (in millions) | 2025 | 2024 | |||||||||||||||||||
| Electric operating revenues | $ | 18,318 | $ | 17,811 | $ | 507 | 3 | % | |||||||||||||
| Natural gas operating revenues | 6,617 | 6,608 | 9 | — | % | ||||||||||||||||
| Total operating revenues | 24,935 | 24,419 | 516 | 2 | % | ||||||||||||||||
| Cost of electricity | 2,609 | 2,261 | 348 | 15 | % | ||||||||||||||||
| Cost of natural gas | 1,107 | 1,192 | (85) | (7) | % | ||||||||||||||||
| Operating and maintenance | 11,337 | 11,787 | (450) | (4) | % | ||||||||||||||||
| SB 901 securitization charges, net | 35 | 33 | 2 | 6 | % | ||||||||||||||||
| Wildfire-related claims, net of recoveries | 100 | 94 | 6 | 6 | % | ||||||||||||||||
| Wildfire Fund expense | 352 | 383 | (31) | (8) | % | ||||||||||||||||
| Depreciation, amortization, and decommissioning | 4,634 | 4,189 | 445 | 11 | % | ||||||||||||||||
| Total operating expenses | 20,174 | 19,939 | 235 | 1 | % | ||||||||||||||||
| Operating income | 4,761 | 4,480 | 281 | 6 | % | ||||||||||||||||
| Interest income | 509 | 589 | (80) | (14) | % | ||||||||||||||||
| Interest expense | (2,713) | (2,781) | 68 | (2) | % | ||||||||||||||||
| Other income, net | 328 | 319 | 9 | 3 | % | ||||||||||||||||
| Income before income taxes | 2,885 | 2,607 | 278 | 11 | % | ||||||||||||||||
Income tax benefit | (194) | (105) | (89) | 85 | % | ||||||||||||||||
| Net income | 3,079 | 2,712 | 367 | 14 | % | ||||||||||||||||
Preferred stock dividend requirement | 14 | 14 | — | — | % | ||||||||||||||||
| Income Attributable to Common Stock | $ | 3,065 | $ | 2,698 | $ | 367 | 14 | % | |||||||||||||
Operating Revenues
The Utility’s electric and natural gas operating revenues increased by $516 million, or 2%, in 2025 compared to 2024. The increase was primarily due to:
•approximately $650 million in revenues to recover the costs associated with extended operations at DCPP in 2025, with no comparable amount in 2024;
•approximately $500 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2025, as compared to 2024;
•approximately $380 million in revenue recognition authorized in the 2024 Transmission Revenue Requirement Reclassification Memo Account (“TRRRMA”) final decision in 2025, with no comparable amount in 2024; and
•$348 million in revenues to recover the cost of electricity procurement in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income,
partially offset by:
•approximately $540 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in 2024, with no comparable amount 2025;
•approximately $430 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K) in 2024, with no comparable amount in 2025;
•approximately $260 million less revenue recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below);
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•approximately $120 million less in revenues authorized in the General Office Sale Memorandum Account (“GOSMA”) petition for modification final decision in 2025, as compared to 2024; and
•$85 million less in revenues to recover the cost of natural gas in 2025, as compared to 2024. These costs are passed through to customers and do not impact Net income.
Cost of Electricity
The Utility’s Cost of electricity represents the cost of power and fuel used in the Utility’s generating facilities and purchased from third parties to serve customers. Cost of electricity includes fuel supplied to other third-party generating facilities, costs to comply with California’s cap-and-trade program, realized gains and losses on price risk management activities (see Note 10 of the Notes to the Consolidated Financial Statements in Item 8), and net power purchases from and sales to the CAISO electricity markets and directly from third parties. The Cost of electricity increased by $348 million in 2025 as compared to 2024. This increase was primarily the result of higher procurement costs, including local RA contract costs, FERC approved transmission owner rate case settlement costs, and higher nuclear fuel amortization, partially offset by increased CAISO market net sales, increased sales of various RPS resources, and lower net costs associated with fuel for utility owned generation and contracted generation.
Cost of Natural Gas
The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. The Cost of natural gas decreased by $85 million in 2025 as compared to 2024. This decrease was primarily the result of lower GHG emission volumes, favorable price risk management activity resulting from reduced natural gas market volatility, and a reduction in contracted transport capacity, partially offset by higher natural gas procurement costs attributed to increased prices and demand, along with additional contracted storage capacity.
Operating and Maintenance
The Utility’s Operating and maintenance expense decreased by $450 million, or 4%, in 2025 compared to 2024. The decrease was primarily due to:
•approximately $560 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” in the 2024 Form 10-K) in 2024, with no comparable costs in 2025;
•approximately $540 million of previously deferred expenses authorized in the 2022 WMCE proceeding as part of interim rate relief (see “2022 WMCE Application” below) in 2024, with no comparable costs in 2025;
•approximately $260 million less expense recognized in 2025, as compared to 2024, authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below);
•approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to reclassify these costs to operating expense in 2024, with no comparable costs 2025; and
•approximately $150 million less expense recognized in 2025, as compared to 2024, authorized in the GOSMA petition for modification final decision,
partially offset by:
•approximately $570 million in costs associated with extended operations at DCPP in 2025, with no comparable costs in 2024;
•approximately $500 million more in previously deferred expenses in 2025, as compared to 2024, related to interim rate relief authorized in the 2023 WMCE proceeding (see “2023 WMCE Application” below); and
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•approximately $150 million in previously deferred expenses related to VMBA disallowances in the 2023 WMCE final decision (see “2023 WMCE Application” below) in 2025, with no comparable costs in 2024.
Depreciation, Amortization, and Decommissioning
The Utility’s Depreciation, amortization, and decommissioning expenses increased by $445 million, or 11%, in 2025 compared to 2024. The increase was primarily due to the growth in plant balance from capital additions and the recognition of deferred depreciation expense.
Interest Income
The Utility’s Interest income decreased by $80 million, or 14%, in 2025 compared to 2024. The decrease was primarily due to a decrease in interest rates and a decrease in interest bearing account balances in 2025, compared to 2024.
Income Tax Benefit
The Utility’s Income tax benefit increased by $89 million, or 85%, in 2025 compared to 2024. The increase was primarily due to an increased tax repairs deduction and an additional deduction for certain costs attributable to electric generation.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
| 2025 | 2024 | |||||||||
| Federal statutory income tax rate | 21.0 | % | 21.0 | % | ||||||
| Increase (decrease) in income tax rate resulting from: | ||||||||||
State income tax (net of federal benefit) (1) | (0.6) | % | (0.8) | % | ||||||
Effect of regulatory treatment of fixed asset differences (2) | (27.4) | % | (25.2) | % | ||||||
| Nontaxable or nondeductible items | 1.1 | % | 0.4 | % | ||||||
| Tax credits | (0.9) | % | (0.9) | % | ||||||
| Changes in unrecognized tax benefits | 0.1 | % | 1.9 | % | ||||||
Other, net | — | % | (0.4) | % | ||||||
| Effective tax rate | (6.7) | % | (4.0) | % | ||||||
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
LIQUIDITY AND FINANCIAL RESOURCES
Overview
PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term.
PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.
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PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.
Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2031. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026. As a result, PG&E Corporation expects to pay state income taxes in 2026. See “Tax Matters” above for a discussion of events that could limit PG&E Corporation’s ability to use its net operating losses.
PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
As of December 31, 2025, PG&E Corporation and the Utility had access to approximately $4.5 billion of total liquidity comprised of $353 million of the Utility’s Cash and cash equivalents, $360 million of PG&E Corporation’s Cash and cash equivalents, and $3.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.
Credit Ratings
Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s unsecured credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s unsecured credit rating remains below investment grade with one of the major credit rating agencies, the Utility generally does not receive unsecured credit from its energy procurement counterparties, and it may be required to increase its collateral postings if its credit rating is downgraded.
Restrictive Debt Covenants
PG&E Corporation’s and the Utility’s credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants. One financial covenant requires that the ratio of total consolidated debt to total consolidated capitalization as of the end of each fiscal quarter be no more than 70% for PG&E Corporation and 65% for the Utility.
The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. PG&E Corporation’s and the Utility’s various credit agreements and the DOE Loan Guarantee Agreement contain provisions that may result in an event of default if there was a failure to meet payment terms or observe other covenants under other financing arrangements that could result in an acceleration of payments due. Such provisions are referred to as “cross-default” provisions. As of December 31, 2025, PG&E Corporation and the Utility remain in compliance with all financial covenants.
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of December 31, 2025, PG&E Corporation and the Utility had cash and cash equivalents of $360 million and $353 million, respectively.
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Financial Resources
Equity Financings
PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, its share price, its earnings, the timing and outcome of ratemaking proceedings, the timing and terms of other financings, and the outcome of the Wildfire-Related Securities Claims. See “Wildfire-Related Securities Litigation” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
Debt Financings, Credit Facilities, and Term Loans
The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.
For more information, see “Credit Facilities and Term Loans” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
DOE Loan Guarantee Agreement
As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future.
For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K.
Other Financings
Citizens Energy Corporation
On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. The transactions contemplated by the agreement are subject to FERC and CPUC approvals.
Dividends
PG&E Corporation has announced a dividend policy entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions determined by the Board may be impacted by earnings, cash flows, credit metrics, and other business conditions.
For information on dividend declarations and payments, see Notes 6 and 7 to the Consolidated Financial Statements in Part II, Item 8.
Utility Cash Flows
PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the year ended December 31, 2025 and 2024.
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The Utility’s cash flows were as follows:
| Year Ended December 31, | |||||||||||||
| (in millions) | 2025 | 2024 | |||||||||||
| Net cash provided by operating activities | $ | 9,035 | $ | 8,268 | |||||||||
| Net cash used in investing activities | (12,316) | (11,375) | |||||||||||
| Net cash provided by financing activities | 2,915 | 3,348 | |||||||||||
| Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents | $ | (366) | $ | 241 | |||||||||
Operating Activities
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities increased by $767 million, or 9%, in 2025 compared to 2024. This increase was primarily due to:
•an increase in collections driven in part by recoveries related to DCPP extended operations;
•a decrease in non-wildfire related insurance costs; and
•a decrease in wildfire-related payments, net of recoveries.
Future cash flow from operating activities will be affected by various factors, including:
•the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;
•the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 14 of the Notes to the Consolidated Financial Statements in Part II, Item 8);
•the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);
•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and
•the timing and amount of electric and natural gas commodity price volatility and differences between commodity costs and revenue collections.
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
Investing Activities
The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments.
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The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2025, compared to December 31, 2024.
| (in millions) | Year Ended December 31, | ||||||
| Cash used in investing activities - 2024 | $ | (11,375) | |||||
| Capital expenditures | (1,418) | ||||||
| Net purchases related to customer credit trust investments | (186) | ||||||
| Net purchases related to self-insurance investment and other investing activities | 663 | ||||||
| Net increase in cash used in investing activities | (941) | ||||||
| Cash used in investing activities - 2025 | $ | (12,316) | |||||
Net cash used in investing activities increased by $0.9 billion, or 8%, in 2025 compared to 2024. This increase was primarily due to a $349 million payment for the purchase of the Oakland General Office, as discussed in Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8, along with higher investments in new business, capacity projects, and distribution system hardening. These increases were partially offset by lower funding related to self‑insurance investments in 2025 compared to 2024.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will invest $12.4 billion in capital expenditures in 2026.
Financing Activities
Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation.
The following table summarizes changes in key components of the Utility’s financing cash flows for the year ended December 31, 2025, compared to December 31, 2024.
| (in millions) | Year Ended December 31, | ||||
| Cash provided by financing activities - 2024 | $ | 3,348 | |||
| Net borrowings under credit facilities | 6,574 | ||||
| Net borrowings under term loan | 2,675 | ||||
| Repayments of long-term debt, net of proceeds | (1,113) | ||||
| AB 1054 recovery bonds issuance | (1,409) | ||||
| Short-term debt issuance | (1,999) | ||||
| Dividend payments | (325) | ||||
| Proceeds from DWR loan | (980) | ||||
| Equity contributions from PG&E Corporation | (3,785) | ||||
| Other financing activities | (71) | ||||
| Net decrease in cash provided by financing activities | (433) | ||||
| Cash provided by financing activities - 2025 | $ | 2,915 | |||
Net cash provided by financing activities decreased by $433 million, or 13%, during the year ended December 31, 2025 as compared to the same period in 2024. The decrease was primarily due to:
•$3.8 billion decrease in equity contributions received from PG&E Corporation;
•$1.1 billion increase in repayments of long-term debt, net of proceeds;
•$2.7 billion decrease in net borrowings under term loan;
•$1.4 billion of proceeds related to the issuance of senior secured recovery bonds under the AB 1054 securitization in 2024, with no similar transaction in 2025;
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•$2.0 billion decrease in proceeds related to short-term debt issuance;
•$980 million decrease in proceeds related to the DWR loan; and
•$325 million increase in dividend payments.
Partially offset by:
•$6.6 billion increase in net borrowings under credit facilities.
REGULATORY MATTERS
The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, 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 or outcome of the following proceedings.
Key updates to regulatory matters include the following:
•In February 2026, the CPUC issued a final decision in the Utility’s 2023 WMCE proceeding, approving recovery of $1.9 billion of costs.
•In February 2026, the OEIS issued a final decision approving the Utility’s 2026–2028 WMP. In December 2025, the Utility submitted its 2025 safety certificate request to OEIS.
•In December 2025, the CPUC issued a final decision in the Utility’s 2026 Cost of Capital proceeding that set the Utility’s ROE at 9.98% effective January 1, 2026 and approved a yield spread adjustment.
•In December 2025, the CPUC approved a resolution that updated CPUC guidelines for implementation of the SB 884 undergrounding program.
•In November 2025, the Utility filed the Kincade and Dixie AB 1054 Wildfire Cost Review and Recovery Proceeding application requesting recovery of approximately $1.59 billion of WEMA costs, review of costs drawn from the Wildfire Fund, and recovery of $314 million of CEMA costs.
•In August 2025, the FERC approved an all-party settlement in the Utility’s Transmission Owner Rate Case for 2024 (the “TO21” rate case).
•In August 2025, the CPUC issued a final decision that increases the cost cap for 2025 and 2026 by an aggregate $2.38 billion in connection with the Order Instituting Rulemaking (“OIR”) to Establish Energization Timelines.
•In September 2025, the CPUC issued a final decision approving $1.06 billion in cost recovery in the 2022 WMCE proceeding.
•In May 2025, the Utility filed its 2027 GRC application with the CPUC.
Cost Recovery Proceedings
Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FRMMA, WMPMA, VMBA, WMBA, among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.
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In recent years, the Utility has recorded significant amounts to these accounts. Because rate recovery may require CPUC authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2025, the Utility had recorded an aggregate amount of approximately $2.2 billion in costs for the CEMA, WEMA, FRMMA, WMPMA, VMBA, and WMBA, substantially all of which was accounted for as long term. See Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
If the amount of the costs recorded in these accounts increases, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Part II, Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below.
Key updates to the Utility’s cost recovery proceedings are summarized in the following table:
| Proceeding | Request (1) | Status | ||||||||||
| 2022 WMCE | $1.36 billion of cost recovery | Final decision authorizing $1.06 billion of total cost recovery issued September 2025. | ||||||||||
| 2023 WMCE | $2.18 billion of cost recovery | Final decision authorizing $1.9 billion of costs issued February 2026. | ||||||||||
| 2024 WMCE | $596 million of cost recovery | Application filed November 2024. | ||||||||||
| 2023 WGSC | $2.5 billion of cost recovery | Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024. | ||||||||||
| Kincade and Dixie AB 1054 | Review of 2019 Kincade fire and 2021 Dixie fire costs, including recovery of approximately $1.9 billion | Application filed November 2025. | ||||||||||
(1) The revenue requirement amounts requested do not include interest.
Wildfire Mitigation and Catastrophic Events Cost Recovery Applications
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 the 2022 WMCE 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 consisted of $1.2 billion in expenses and $136 million in capital expenditures.
On September 26, 2025, the CPUC issued a final decision adopting the settlement agreement and authorizing total cost recovery for this matter of $1.06 billion. The final decision disallowed $217 million in VMBA costs.
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 the 2023 WMCE 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.
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On September 16, 2024, the CPUC issued a final decision on interim rate recovery that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024.
On February 5, 2026, the CPUC voted out a final decision, which approved recovery of $1.9 billion of costs. The final decision denied recovery of $173 million in vegetation management costs.
2024 WMCE Application
On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in the 2024 WMCE application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023.
The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in the CEMA.
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 efforts 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 millions) | Recorded Costs | ||||||
WMPMA | $ | 2,095 | |||||
FRMMA | 165 | ||||||
Gas storage balancing account | 101 | ||||||
In line inspection memorandum account | 92 | ||||||
Other | 45 | ||||||
Total | $ | 2,498 | |||||
In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024.
On June 12, 2025, the CPUC issued a decision extending the statutory deadline in the proceeding from June 30, 2025 to March 31, 2026.
Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application
On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA.
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The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as the Utility continues to resolve claims and draw from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 14 of the Notes to the Consolidated Financial Statements.
The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months.
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.
Recent insider activity
| Date | Insider | Role | Action | Shares | Price | Value |
|---|---|---|---|---|---|---|
| 2026-06-02 | Cooper Kerry Whorton | Director | Sell | -1,250 | $16.50 | -$20,625 |
| 2026-04-28 | Glickman Jason M | EVP, Strategy and Growth | Sell | -47,264 | $16.35 | -$772,766 |
| 2026-04-28 | Poppe Patricia K indirect | Chief Executive Officer | Sell | -31,250 | $16.39 | -$512,188 |
| 2026-03-17 | Cooper Kerry Whorton | Director | Sell | -2,500 | $18.68 | -$46,700 |
Source: SEC Form 4 filings.
Next expected filings
- ~2026-07-30 10-Q expected by 2026-08-13 (in 45 days)
- ~2026-10-22 10-Q expected by 2026-11-05 (in 129 days)
- ~2027-02-11 10-K expected by 2027-02-28 (in 241 days)
- ~2027-04-22 10-Q expected by 2027-05-06 (in 311 days)
Predicted from historical filing cadence; not an SEC commitment.
Recent SEC filings
- 2026-06-03 8-K Other Events; Financial Statements and Exhibits
- 2026-04-23 10-Q Quarterly Report
- 2026-04-23 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits
- 2026-04-09 DEF 14A Proxy Statement
- 2026-02-20 8-K Other Events; Financial Statements and Exhibits
- 2026-02-19 8-K Other Events; Financial Statements and Exhibits
- 2026-02-12 10-K Annual Report
- 2026-02-12 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits
- 2025-12-17 8-K Officer/Director Change; Bylaws/Articles Amended; Other Events; Financial Statements and Exhibits
- 2025-10-23 10-Q Quarterly Report
- 2025-10-23 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits
- 2025-10-02 8-K Other Events; Financial Statements and Exhibits
- 2025-09-24 8-K Material Agreement Entered; Material Financial Obligation; Other Events; Financial Statements and Exhibits
- 2025-09-12 8-K Officer/Director Change
- 2025-07-31 10-Q Quarterly Report