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What changed in PG&E Corporation's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of PG&E Corporation's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+518 added−688 removedSource: 10-K (2026-02-12) vs 10-K (2025-02-13)

Top changes in PG&E Corporation's 2025 10-K

518 paragraphs added · 688 removed · 391 edited across 9 sections

Item 1. Business

Business — how the company describes what it does

139 edited+21 added−76 removed117 unchanged
Biggest changeAs a result of actions already taken by PG&E Corporation and the Utility, the companies have: • Delivered electricity to retail customers in 2024 that was over 90% GHG free (see “Electricity Resources” below for more information). • Helped customers avoid emissions and manage energy costs through robust energy efficiency programs. • Managed contracts for more than 4.6 GW of battery energy storage to be deployed over the next several years and operated 183 MW of Utility-owned battery storage, strengthening California’s grid efficiency and reliability. • Helped enable the total number of electric vehicles operating in the Utility’s service area to exceed 675,000; installed more than 3,800 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and deployed the first-in-the-nation 100% electric school bus fleet that is also equipped with groundbreaking vehicle-to-grid technology. • Brought the total number of interconnected private solar customers to more than 880,000 and total number of customers who have installed battery storage at their homes or businesses to more than 120,000.
Biggest changeAs 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.
PG&E Corporation and the Utility measure their progress toward the 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.
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.
MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 17 Federal Energy Regulatory Commission and California Independent System Operator Corporation The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the siting, construction, operation, maintenance, and safety obligations of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 15 Federal Energy Regulatory Commission and California Independent System Operator Corporation The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the siting, construction, operation, maintenance, and safety obligations of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County. 28 Generation Resources from Third Parties The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. See “Ratemaking Mechanisms” above.
All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County. Generation Resources from Third Parties The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. See “Ratemaking Mechanisms” above.
Key elements of PG&E Corporation’s and the Utility’s approach to diversity, equity, inclusion, and belonging include integrating inclusion and belonging into the employee experience with a focus on equity and interrupting bias in hiring, promotion, retention and compensation, heightened cultural awareness programming to encourage understanding and importance of inclusion and belonging, and integrating useful content into training, development, and performance support resources.
Key elements of PG&E Corporation’s and the Utility’s approach to inclusion and belonging include integrating inclusion and belonging into the employee experience with a focus on equity and interrupting bias in hiring, promotion, retention and compensation, heightened cultural awareness programming to encourage understanding and importance of inclusion and belonging, and integrating useful content into training, development, and performance support resources.
PG&E Corporation and the Utility are also making progress on transitioning the gas system to cleaner fuels and supporting efforts to accelerate building electrification. The objective is to do so in an orderly manner to achieve a positive customer and community experience, while reducing natural gas system investments in targeted electrified communities.
PG&E Corporation and the Utility are also making progress on transitioning the gas system to cleaner fuels and supporting efforts to accelerate building electrification. Their objective is to do so in an orderly manner to achieve a positive customer and community experience, while reducing natural gas system investments in targeted electrified communities.
PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction. PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitably-paid workforce.
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.
The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service area) and to third-party natural gas storage customers. 30 Natural Gas Supplies The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.
The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service area) and to third-party natural gas storage customers. Natural Gas Supplies The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.
As a result, the Utility could lose customers (residential, commercial, and industrial) or experience limited growth in the municipality. See “Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system” in Item 1A. Risk Factors.
As a result, the Utility could lose customers (residential, commercial, and industrial) or experience limited growth in the applicable municipality. See “Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system” in Item 1A. Risk Factors.
Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.
Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. 12 See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.
At the federal level, the Utility is regulated primarily 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.
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.
The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. Customer rates are determined by dividing the revenues that the Utility is authorized to collect from customers by the amount of power that the Utility is forecasted to sell.
The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. 18 Customer rates are determined by dividing the revenues that the Utility is authorized to collect from customers by the amount of power that the Utility is forecasted to sell.
A key element of preparing the Utility for the physical risks of climate change is a system-wide CAVA of the Utility’s assets, operations, and services, filed with the CPUC in May 2024.
A key element of preparing the Utility for the physical risks of climate change is a system-wide CAVA of the Utility’s assets, operations, and services, filed with the CPUC in 2024.
PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and virtues that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, innovation, and community service.
PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and virtues that should be cultivated. Each year, the Utility honors employees whose work embodies safety, inclusion and belonging, environmental leadership, innovation, and community service.
As the Utility’s asset inspections have identified less resilient equipment, the Utility has hardened its system by fixing significantly more equipment than in prior years. Hardening methods also include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground.
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.
For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A. 21 Electricity Transmission Owner Rate Cases The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect through rates in TO rate cases.
For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A. 19 Electricity Transmission Owner Rate Cases The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect through rates in TO rate cases.
People The people element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders. 12 PG&E Corporation’s and the Utility’s goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe.
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. 11 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.
To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the energy system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased utilization of renewable energy combined with investments in the grid and energy storage.
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.
Owned Generation Facilities At December 31, 2024, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below: Generation Type County Location Number of Units Net Operating Capacity (MW) Nuclear (1) : Diablo Canyon San Luis Obispo 2 2,240 Hydroelectric (2) : Conventional 16 counties in northern and central California 91 2,628 Helms pumped storage Fresno 3 1,212 Fossil fuel-fired: Colusa Generating Station Colusa 1 657 Gateway Generating Station Contra Costa 1 580 Humboldt Bay Generating Station Humboldt 10 163 Elkhorn Battery Energy Storage System Monterey County 1 183 Photovoltaic (3) : Various 12 152 Total 121 7,815 (1) The Utility’s DCPP consists of two nuclear power reactor units, Units 1 and 2.
Owned Generation Facilities As of December 31, 2025, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below: Generation Type County Location Number of Units Net Operating Capacity (MW) Nuclear (1) : Diablo Canyon San Luis Obispo 2 2,240 Hydroelectric (2) : Conventional 16 counties in northern and central California 91 2,628 Helms pumped storage Fresno 3 1,212 Fossil fuel-fired: Colusa Generating Station Colusa 1 657 Gateway Generating Station Contra Costa 1 580 Humboldt Bay Generating Station Humboldt 10 163 Elkhorn Battery Energy Storage System Monterey County 1 183 Photovoltaic (3) : Various 12 152 Total 121 7,815 (1) DCPP consists of two nuclear power reactor units, Units 1 and 2.
These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, Chief People Officer, in partnership with the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ diversity, equity, inclusion, and belonging strategy, practices, and performance.
These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, Chief People Officer, in partnership with the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ inclusion and belonging strategy, practices, and performance.
The NRC operating license for Unit 1 expired in 2024. Unit 2 will expire in 2025. Both remain in effect pending completion of the ongoing federal relicensing review. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below. (2) The Utility’s hydroelectric system consists of 94 generating units at 58 powerhouses.
The NRC operating license for Unit 1 expired in 2024, and the operating license for Unit 2 expired in 2025. Both remain in effect pending completion of the ongoing federal relicensing review. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below. (2) The Utility’s hydroelectric system consists of 94 generating units at 58 powerhouses.
Visual management allows teams to see how they are performing against their most important metrics using real-time data. Teams throughout PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of employees closest to the work with the goals and objectives of senior leadership.
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.
The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000. This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity.
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.
Ratemaking Mechanisms The Utility operates under a “cost-of-service” ratemaking model, which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and to earn a return on invested capital.
Ratemaking Mechanisms The Utility operates under a “cost-of-service” ratemaking model, which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and have a reasonable opportunity to earn a return on invested capital.
The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one compressor station on its local transmission system that are used to move gas through the Utility’s pipelines.
The Utility owns and operates seven natural gas compressor stations on its backbone transmission system and one compressor station on its local transmission system that are used to move gas through the Utility’s pipelines.
See “Emissions Data” below. 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. California laws and regulations have also established targets for GHG emissions. See “Greenhouse Gas Emissions Regulation” above.
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. California laws and regulations have also established targets for GHG emissions. See “Greenhouse Gas Emissions Regulation” above.
These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates and by the CAISO in its transmission access charges to wholesale customers. For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7. MD&A.
These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates and by the CAISO in its transmission access charges to wholesale customers. For more information, see “Regulatory Matters - Transmission Owner Rate Case for 2024” in Item 7. MD&A.
For more information about the Utility’s GRC, see “Regulatory Matters - 2023 General Rate Case” in Item 7. MD&A.
For more information about the Utility’s GRC, see “Regulatory Matters - 2027 General Rate Case” in Item 7. MD&A.
The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities it regulates in California. 18 The OEIS is a state agency responsible for reviewing and approving the Utility’s WMP and for evaluating the Utility’s implementation of the WMP.
The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities it regulates in California. 16 The OEIS is a state agency responsible for reviewing and approving or rejecting the Utility’s WMP and for evaluating the Utility’s implementation of the WMP.
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 can be found below in Item 8. Financial Statements and Supplementary Data.
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.
During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the year ended December 31, 2024, DCPP achieved an average capacity factor of 93%.
During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the year ended December 31, 2025, DCPP achieved an average capacity factor of 90%.
(PG&E Corporation and the Utility define retirement age as 55 years and older.) The Utility’s contractors and subcontractors include approximately 35,000 individuals from approximately 1,200 contractor companies. Human Capital Management PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce.
(PG&E Corporation and the Utility define retirement age as 55 years and older.) The Utility’s contractors and subcontractors include approximately 39,000 individuals from approximately 1,200 contractor companies. Human Capital Management 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.
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. California Public Utilities Commission The CPUC is a regulatory agency that regulates privately owned public utilities in California.
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. California Public Utilities Commission The CPUC regulates privately owned public utilities in California.
The Utility conducts an annual employee survey to measure and improve employee engagement. Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures.
The Utility conducts employee surveys to measure and improve employee engagement. PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures.
Of the Utility’s regular employees, approximately 17,600 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”).
Of the Utility’s regular employees, approximately 17,500 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) International Federation of Professional and Technical Engineers 20; and the Service Employees International Union Local 24/7 (“SEIU”).
Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. On December 31, 2024, the Utility’s natural gas system consisted of approximately 45,200 miles of distribution pipelines, approximately 5,700 miles of backbone and local transmission pipelines, and various storage facilities.
Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. On December 31, 2025, the Utility’s natural gas system consisted of approximately 45,400 miles of distribution pipelines, approximately 5,500 miles of backbone and local transmission pipelines, and various storage facilities.
During 2024, the Utility purchased approximately 287,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 50% of the total natural gas volume the Utility purchased during 2024.
During 2025, the Utility purchased approximately 304,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 56% of the total natural gas volume the Utility purchased during 2025.
In 2024, the Utility continued upgrading transmission pipelines to allow for the use of in-line inspection tools. 31 Natural Gas Operating Statistics The following table shows the Utility’s operating statistics from 2022 through 2024 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.
In 2025, the Utility continued upgrading transmission pipelines to allow for the use of in-line inspection tools. 26 Natural Gas Operating Statistics The following table shows the Utility’s operating statistics from 2023 through 2025 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.
The Utility continues its expanded training for supervisors. Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations.
Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local and qualified candidates that reflect the communities the Utility serves for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations.
For costs related to AROs, see “Asset Retirement Obligations” in Note 2 of the Notes to the Consolidated Financial Statements in Item 8. Human Capital Employees and Contractors As of December 31, 2024, PG&E Corporation had 10 employees and the Utility had approximately 28,400 regular employees.
For costs related to AROs, see “Asset Retirement Obligations” in Note 2 of the Notes to the Consolidated Financial Statements in Item 8. 21 Human Capital Employees and Contractors As of December 31, 2025, PG&E Corporation had 10 employees, and the Utility had approximately 29,000 regular employees.
The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident. 32 Competition Trends in Market Demand and Competitive Conditions in the Electricity Industry The Utility expects customer electric load to increase in coming years primarily as a result of electric vehicle adoption, data centers, and building electrification.
The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident. 27 Competition Trends in Market Demand The Utility expects customer electric load to increase in coming years primarily as a result of data center usage, electric vehicle adoption, and building electrification.
In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including: • Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them in less than one-tenth of a second in the event of a disturbance to help prevent potential ignitions.
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.
Base Revenues General Rate Cases The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base.
Base Revenues General Rate Cases The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, Utility-owned electric generation operations, gas transmission and storage facilities, and an opportunity to earn authorized rate of return from the cost of capital decision.
Risk Factors. 33 Competition in the Natural Gas Industry The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.
For risks in connection with increasing competition, see Item 1A. Risk Factors. Competitive Conditions in the Natural Gas Industry The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.
Natural Gas Utility Operations The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service area.
(3) These amounts represent revenues authorized to be billed. 25 Natural Gas Utility Operations The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service area.
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.
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.
Diversity, Equity, Inclusion, and Belonging PG&E Corporation’s and the Utility’s goal is to foster a diverse, equitable, and inclusive workforce culture where all employees find it enjoyable to work with and for PG&E Corporation and the Utility and feel they belong.
Inclusion and Belonging PG&E Corporation’s and the Utility’s goal is to foster a workplace culture of inclusion and belonging where all employees find it enjoyable to work with and for PG&E Corporation and the Utility and feel they belong.
As a result, the Utility’s CPUC-jurisdictional revenue requirement is the sum of the following: • expenses; • depreciation; 20 • taxes; and • the product of the Utility’s rate of return (i.e., the cost of capital for long-term debt and equity) and its rate base.
As a result, the Utility’s CPUC-jurisdictional revenue requirement is the sum of the following: • expenses; • depreciation; • taxes; and • the product of the Utility’s rate of return (i.e., the cost of capital for long-term debt and equity) and its rate base (i.e. the value of the Utility’s investments in generation and distribution assets and general plant).
The Utility files an application with the CPUC, generally every three years, requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear facilities. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers.
The Utility files an application with the CPUC, generally every three years, requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear facilities.
The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, put upward rate pressure on non-NEM customers.
The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, put upward rate pressure on non-NEM customers. The successor to the NEM tariffs, the Net Billing Tariff (“NBT”), reduces but does not eliminate the upward rate pressure.
Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume.
Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s net income is not impacted by fluctuations in sales.
(2) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (3) These amounts represent revenues authorized to be billed.
(2) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties, into the wholesale market to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”). In addition, the utilities are required to obtain CPUC approval of their BPPs based on long-term demand forecasts.
The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties, into the wholesale market to meet customer demand according to which resources are the least expensive. In addition, the utilities are required to obtain CPUC approval of their bundled procurement plans (“BPPs”), which are based on customer demand forecasts.
No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2024, 2023, or 2022. 2024 2023 2022 Customers (average for the year) 5,606,873 5,584,185 5,562,223 Deliveries (in GWh) (1) 74,111 72,933 77,769 Revenues (in millions): Residential $ 7,504 $ 6,041 $ 6,130 Commercial 7,201 5,643 5,416 Industrial 2,065 1,784 1,626 Agricultural 1,815 1,413 1,830 Public street and highway lighting 103 83 77 Other, net (2) (47) 136 (247) Subtotal 18,641 15,100 14,832 Regulatory balancing accounts (3) (830) 2,324 228 Total operating revenues $ 17,811 $ 17,424 $ 15,060 Selected Statistics: Average annual residential usage (kWh) 5,261 5,217 5,564 Average billed revenues per kWh: Residential $ 0.2888 $ 0.2356 $ 0.2253 Commercial 0.2528 0.2007 0.1896 Industrial 0.1475 0.1294 0.1177 Agricultural 0.3597 0.2984 0.2435 Net plant investment per customer $ 11,460 $ 10,720 $ 9,967 (1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.
No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2025, 2024, or 2023. 2025 2024 2023 Customers (average for the year) 5,656,450 5,606,873 5,584,185 Deliveries (in GWh) (1) 71,791 74,111 72,933 Revenues (in millions): Residential $ 6,976 $ 7,504 $ 6,041 Commercial 7,022 7,201 5,643 Industrial 1,929 2,065 1,784 Agricultural 1,825 1,815 1,413 Public street and highway lighting 105 103 83 Other, net (2) 72 (47) 136 Subtotal 17,929 18,641 15,100 Regulatory balancing accounts (3) 389 (830) 2,324 Total operating revenues $ 18,318 $ 17,811 $ 17,424 Selected Statistics: Average annual residential usage (kWh) 4,931 5,261 5,217 Average billed revenues per kWh: Residential $ 0.2836 $ 0.2888 $ 0.2356 Commercial 0.2527 0.2528 0.2007 Industrial 0.1403 0.1475 0.1294 Agricultural 0.3636 0.3597 0.2984 Net plant investment per customer $ 12,710 $ 11,460 $ 10,720 (1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.
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, administration, and general expenses) and capital costs (e.g., depreciation, and financing expenses). The Utility’s costs of equity and long-term debt are generally approved in the CPUC’s cost of capital proceedings.
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, administration, and general expenses) and capital costs (e.g., depreciation, and financing expenses).
These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines.
Rocky Mountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines.
In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of DA and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers.
The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility collects charges intended to recover the generation-related costs that the Utility incurred on behalf of DA and CCA customers while they were the Utility’s customers.
No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2024, 2023 or 2022. 2024 2023 2022 Customers (average for the year) (1) 4,614,080 4,605,628 4,585,126 Gas purchased (MMcf) 219,758 239,756 227,128 Average price of natural gas purchased (price per Mcf) $ 1.99 $ 6.91 $ 7.42 Bundled gas sales (MMcf): Residential 146,842 171,889 160,449 Commercial 55,174 60,248 57,066 Total Bundled Gas Sales 202,016 232,137 217,515 Revenues (in millions): Bundled gas sales: Residential $ 3,089 $ 3,686 $ 3,353 Commercial 984 1,052 1,005 Other 159 (145) 163 Bundled gas revenues 4,232 4,593 4,521 Transportation service only revenue 1,815 1,603 1,534 Subtotal 6,047 6,196 6,055 Regulatory balancing accounts (2) 561 808 565 Total operating revenues $ 6,608 $ 7,004 $ 6,620 Selected Statistics: Average annual residential usage (Mcf) 37 37 37 Average billed bundled gas sales revenues per Mcf: Residential $ 20.74 $ 20.73 $ 20.22 Commercial 16.28 14.99 15.19 Net plant investment per customer $ 5,019 $ 4,749 $ 4,522 (1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.
No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2025, 2024 or 2023. 2025 2024 2023 Customers (average for the year) (1) 4,633,685 4,614,080 4,605,628 Gas purchased (MMcf) 223,619 219,758 239,756 Average price of natural gas purchased (price per Mcf) $ 2.55 $ 1.99 $ 6.91 Bundled gas sales (MMcf): Residential 147,827 146,842 171,889 Commercial 56,986 55,174 60,248 Total Bundled Gas Sales $ 204,813 $ 202,016 $ 232,137 Revenues (in millions): Bundled gas sales: Residential $ 3,651 $ 3,089 $ 3,686 Commercial 1,074 984 1,052 Other 101 159 (145) Bundled gas revenues 4,826 4,232 4,593 Transportation service only revenue 1,937 1,815 1,603 Subtotal 6,763 6,047 6,196 Regulatory balancing accounts (2) (146) 561 808 Total operating revenues $ 6,617 $ 6,608 $ 7,004 Selected Statistics: Average annual residential usage (Mcf) 37 37 37 Average billed bundled gas sales revenues per Mcf: Residential $ 24.39 $ 20.74 $ 20.73 Commercial 17.59 16.28 14.99 Net plant investment per customer $ 5,278 $ 5,019 $ 4,749 (1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.
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.
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.
The Utility expects its GHG-free energy supply to decrease in the near future because, during DCPP’s extended operations, the Utility is required to allocate its GHG-free attributes to certain non-Utility providers.
The Utility expects its GHG-free energy supply to decrease in the near future because, during DCPP’s extended operations, the Utility is required to allocate its GHG-free attributes to certain non-Utility providers. The Utility also allocates or sells certain GHG-free energy supply to eligible non-Utility providers in its service territory pursuant to CPUC directives.
The majority of these emissions came from customer natural gas use. The Utility utilized the CEC’s Power Source Disclosure program methodology to calculate the CO 2 emissions rate associated with the electricity delivered to retail customers in 2023. This resulted in a third-party verified CO 2 emissions rate of 12 pounds of CO 2 per MWh.
The majority of these emissions came from customer natural gas use. 31 The Utility achieved a third-party verified CO 2 emissions rate of 16 pounds of CO 2 per MWh for electricity delivered to retail customers in 2024, using the CEC’s Power Source Disclosure program methodology.
The Utility provides electricity, transmission, and distribution services in its service area. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. For more information, see “Competition” below.
Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. For more information, see “Competition” below.
Their focus is on making it enjoyable to work with and for PG&E Corporation and the Utility. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas service reliability, and improving customer satisfaction.
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.
A strong transmission system supports reliable and affordable service, ability to meet state energy policy goals, and support for a diverse generation mix, including renewable energy. As of December 31, 2024, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV.
A strong transmission system supports reliable and affordable service, ability to meet state energy policy goals, and support for a diverse generation mix, including renewable energy. 24 As of December 31, 2025, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines. The Utility also operated 33 electric transmission substations.
The Utility plans to continue identifying priority adaptive actions by incorporating results from the CAVA into its risk management, planning, and asset management functions. The Utility works to incorporate into its operations scientific information by reviewing relevant scientific literature and to incorporate customer and community perspectives based on its engagement with CPUC-designated disadvantaged and vulnerable communities in the CAVA process.
The Utility plans to continue identifying priority adaptive actions by incorporating results from the CAVA into its risk management, planning, and asset management functions. The Utility works to incorporate scientific information into its operations by reviewing relevant scientific literature.
The Utility’s total capital expenditures (including accruals) are forecasted to be $12.9 billion for 2025, $12.0 billion for 2026, $13.6 billion for 2027, and $14.0 billion for 2028.
The Utility’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.
Recovery of the costs tracked in these memorandum accounts through rates requires CPUC authorization in separate proceedings, the outcome of which the Utility may be unable to predict. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts.
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 reasonable. Recovery of the costs tracked in these memorandum accounts through rates requires CPUC authorization in separate proceedings, the outcome of which the Utility may be unable to predict.
The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account. The CPUC may disallow costs associated with the CPE function that were not incurred in compliance with the CPUC’s decisions and guidance. The CPUC has also approved the Power Charge Indifference Adjustment (“PCIA”).
The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account, subject to demonstrating compliance to the CPUC. The CPUC has also approved the Power Charge Indifference Adjustment (“PCIA”).
The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). Attrition year rate adjustments are generally authorized for cost increases related to invested capital and inflation.
The CPUC conducts a GRC for the Utility every four years. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”).
To set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). In the GRC proceedings, the CPUC also generally approves the level of spending on a forecasted basis.
To set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”).
Hazardous Substance Compliance and Remediation The Utility’s facilities are subject to various regulations adopted by the EPA, including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended. The Utility is also subject to the regulations adopted by other federal agencies responsible for implementing federal environmental laws.
Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through the Utility’s rates, subject to reasonableness review. Hazardous Substance Compliance and Remediation The Utility’s facilities are subject to various regulations adopted by the EPA, including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended.
Air Quality and the Clean Air Act The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes.
For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 17 Air Quality and the Clean Air Act The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes.
The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to retail customers in 2024 represented by each major electric resource, and further discussed below.
The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. In 2025, the Utility estimated total net deliveries of electricity to retail customers were 24,052 GWh.
The Utility is also responsible, as the central procurement entity (“CPE”) for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all CPUC-jurisdictional LSEs in its distribution service area.
For more information, see “Electric Utility Operations - Electricity Resources” below as well as Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 20 The Utility is also responsible, as the central procurement entity (“CPE”) for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all CPUC-jurisdictional LSEs in its distribution service area.
The Utility has identified additional opportunities for investment in the coming years in addition to its forecast, including investments in transportation electrification capacity, FERC-jurisdictional assets, electric distribution capacity, hydroelectric facilities, energy storage, information technology, and automation. The Utility also plans to submit a cost recovery application for its 10-year distribution undergrounding program pursuant to SB 884.
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 continues to operate and rely on the Los Medanos storage field as filed and approved in the 2023 GRC. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later for withdrawal.
The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later for withdrawal.
As of December 31, 2024, the Utility owned 183 MW and has contracted for another 2,435 MW of operational energy storage capacity. The Utility has also procured 2,168 MW of battery energy storage to be deployed over the next several years and is working to procure additional battery energy storage to meet its remaining reliability requirements.
The Utility has also procured 1,884 MW of battery energy storage to be deployed over the next several years and is working to procure additional battery energy storage to meet its remaining reliability requirements.
The Utility focuses on continuous improvement and risk informed decision-making to maximize asset value for customers, while 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.
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. 14 Regulatory Environment The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels.
The Utility’s safety metrics include the number of actual serious incidents or fatalities (“SIF-A”) and high-energy events that could have resulted in a serious injury or fatality (“SIF-P”) where SIF-P rate measures events that could have resulted in a SIF-A per 200,000 hours worked.
The Utility’s safety metrics include the number of actual serious injuries or fatalities (“SIF-A”) and high-energy events that had the potential to result in a serious injury or fatality per 200,000 hours worked (“SIF-P rate”). In 2025, the Utility had four SIF-A incidents, which resulted in one fatality and three serious injuries, and a SIF-P rate of 0.051.
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 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.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeThe Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; wildfire mitigation initiatives (including EPSS, PSPS, vegetation management, asset inspections, and system hardening); design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC general orders (“GOs”) or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance.
Biggest changeThe Utility is subject to extensive federal, state, and local laws, regulations, and orders, including those regarding customer billing; customer service; affiliate transactions; wildfire mitigation initiatives and WMP targets (including EPSS, PSPS, vegetation management, asset inspections, and system hardening); design, construction, operating and maintenance practices; safety and inspection practices; federal electric reliability standards; environmental compliance; resource adequacy; GHG emissions; renewable energy; privacy, including laws like the California Consumer Privacy Act, as amended (“CCPA”), which permits consumers to exercise certain rights with respect to their personal information, including opting out of receiving certain communications and data sharing with third parties; and compliance with CPUC general orders (“GOs”) or other applicable CPUC decisions or regulations.
The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations.
The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to limitations.
Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business or operational disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility.
In addition, severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business or operational disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility.
PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to: • incur or assume indebtedness or guarantees of indebtedness; • incur or assume liens; • sell or dispose of all or substantially all of its property or business; • merge or consolidate with other companies; • enter into any sale-leaseback transactions; and • enter into swap agreements.
PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to: • incur or assume indebtedness or guarantees of indebtedness; • incur or assume liens; • sell or dispose of all or substantially all of their property or business; • merge or consolidate with other companies; • enter into any sale-leaseback transactions; and • enter into swap agreements.
Under Section 382 of the IRC (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” such net operating loss carryforwards and other tax attributes may be subject to certain limitations.
Under Section 382 of the IRC (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” such net operating loss carryforwards and other tax attributes may be subject to limitations.
In general, an ownership change occurs if the aggregate value of the stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years).
In general, an ownership change occurs if the aggregate value of the stock ownership of certain shareholders (generally five percent (5%) 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).
The Ownership Restrictions may also be waived by the Board of Directors on a case-by-case basis. 51 PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to offset future income.
The Ownership Restrictions may also be waived by the Board of Directors on a case-by-case basis. PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to offset future income.
The Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
PG&E Corporation and the Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful.
In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company (“SDGE”) stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful.
Once an ignition has occurred, the Utility is unable to control the extent of damages, which primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
Once an ignition has occurred, the Utility is unable to control the extent of damages, which are primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
For example, the City and County of San Francisco (“San Francisco”) has submitted a petition with the CPUC seeking a valuation of the Utility’s electric assets in or serving San Francisco and has expressed intent to acquire such assets.
For example, the City and County of San Francisco (“San Francisco”) has submitted a petition with the CPUC seeking a valuation of the Utility’s electric assets in or serving San Francisco and has expressed an intent to acquire such assets.
The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited.
The disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited.
The CPUC considers affordability as it adjudicates the Utility’s rate cases, and concerns about affordability could cause the CPUC to approve lesser amounts in the Utility’s ratemaking or cost recovery proceedings.
In addition, the CPUC considers affordability as it adjudicates the Utility’s rate cases, and concerns about affordability could cause the CPUC to approve lesser amounts in the Utility’s ratemaking or cost recovery proceedings.
Additionally, the Utility has experienced shortages in certain items, longer lead times, and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.
Additionally, the Utility has experienced shortages in certain items, longer lead times, and delivery delays as a result of domestic and international raw material and labor shortages. If these inflationary pressures and disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.
The Utility may not be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations.
Accordingly, the Utility may not be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations.
The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, Financial Statements and Supplementary Data of this 2024 Form 10-K.
The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, Financial Statements and Supplementary Data of this 2025 Form 10-K.
For example, the Utility has incurred, and continues to incur, wildfire mitigation and prevention costs before it is clear whether such costs will be recoverable through rates. OEIS has required and may in the future require the Utility to perform work for which the CPUC has not yet authorized recovery.
For example, the Utility has incurred, and continues to incur, wildfire mitigation and prevention costs before it is clear whether such costs will be recoverable through rates. OEIS has required and may in the future require the Utility to perform work for which the CPUC has not yet authorized, and ultimately may not authorize, recovery.
This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: • limiting their ability or increasing the costs to refinance their indebtedness; • limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; • limiting their ability to use operating cash flow in other areas of their business; • increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and • limiting their ability to capitalize on business opportunities. 49 Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks.
This high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: • limiting their ability or increasing the costs to refinance their indebtedness; • limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; • limiting their ability to use operating cash flow in other areas of their business; • increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events such as wildfires; and • limiting their ability to capitalize on business opportunities. 42 Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks.
As a result, the Utility’s hydroelectric generation could change, and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits.
As a result, the Utility’s hydroelectric generation could change, and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits imposed by California.
In particular, the risk posed by wildfires, including during the recent wildfire seasons, has increased in the Utility’s service area as a result of an ongoing extended period of drought, bark beetle infestations in the California forest, and wildfire fuel increases due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors.
In particular, the risk posed by wildfires, including during the recent wildfire seasons, has increased in the Utility’s service area as a result of an ongoing extended period of drought, bark beetle infestations in the California forest, and vegetation growth due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors.
Higher steps of the process (steps 3 through 6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility’s Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility).
Higher steps of the process (steps 3 through 6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility’s Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility, which could be revoked).
Additionally, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility.
Additionally, the application of the Ownership Restrictions, as defined in the Amended Articles, will be determined on the basis of a number of shares outstanding that differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility.
If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the AB 1054 disallowance cap.
If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the disallowance cap under AB 1054 and SB 254.
For more information about the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility may be unable to recover all or a significant portion of its costs in excess of insurance coverage in connection with wildfires through rates.
For more information about the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, and the Wildfire-Related Securities Claims, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 33 The Utility may be unable to recover all or a significant portion of its costs in excess of insurance coverage in connection with wildfires through rates.
Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054.
Also, the Utility will not be able to obtain any recovery from the Continuation Account for wildfire-related losses in any year that such losses do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054.
For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack” below.
For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, physical attack, or technology failure” below.
Other factors that could increase customer rates include increases in the Utility’s pass-through commodity costs, cost shifts resulting from self-generation of electricity by customers, decreased gas system load, technological developments, changes in federal or state subsidies, a decrease in the volume of sales, or load growth that is slower than PG&E Corporation and the Utility forecast.
Other factors that could increase customer rates include increases in the Utility’s pass-through commodity costs, cost shifts resulting from self-generation of electricity by customers, decreased gas system load, technological developments, changes in federal or state subsidies, a decrease in the volume of sales, or load growth that is slower or fails to reduce other customers’ bills to the extent PG&E Corporation and the Utility forecast.
Precipitation patterns in California vary significantly from year to year, often leading to periods of severe to extreme drought. Drought conditions often occur and can persist in nearly all of the Utility’s service area depending on the amount of precipitation received in the current or previous water years. More than half of the Utility’s service area is in an HFTD.
Precipitation patterns in California vary significantly from year to year, often leading to periods of severe to extreme drought. Drought conditions often occur and can persist in nearly all of the Utility’s service area depending on the amount of precipitation received in the current or previous water years.
Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund may not ultimately outweigh the substantial costs of the Utility’s contributions to the Wildfire Fund.
Participation in the Wildfire Fund and the Continuation Account has had, and is expected to continue to have, a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund and the Continuation Account may not ultimately outweigh the substantial costs of the Utility’s contributions to the Wildfire Fund or the Continuation Account.
The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, some of which are beyond the Utility’s control, including those that arise from: • the breakdown, failure of, or supply challenges with equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption, or other catastrophic events; • an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow; • the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; • a significant prolonged electrical black-out that results in damage to the Utility’s equipment or losses for customers or other third parties; • the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage; • the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; • the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built; • the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion); • inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; • operator or other human error; • a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences; • an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently; • construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system; 41 • the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities; leaking or spilled insulating fluid from electrical equipment; and release of contaminants caused by the failure of battery energy storage systems; and • attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
For more information, see “The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire” below. 36 The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, some of which are beyond the Utility’s control, including those that arise from: • the breakdown, failure of, or supply challenges with equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption, or other catastrophic events; • an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that causes assets to fail and results in uncontained natural gas flow; • the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; • a significant prolonged electrical black-out that results in damage to the Utility’s equipment or losses for customers or other third parties; • the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage; • the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built; • the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion); • inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; • operator or other human error; • a motor vehicle or aviation incident resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences; • an ineffective records management program that results in the failure to construct, operate, and maintain a utility system safely and prudently; • construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system; • the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities; leaking or spilled insulating fluid from electrical equipment; and release of contaminants caused by the failure of battery energy storage systems; and • attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
PG&E Corporation’s and the Utility’s accrued losses for the 2019 Kincade fire and the 2021 Dixie fire of $1.225 billion and $1.925 billion exceed the amounts of available liability insurance coverage of $430 million and $527 million, respectively. PG&E Corporation and the Utility could also incur substantial costs in excess of insurance coverage in connection with the 2022 Mosquito fire.
PG&E Corporation’s and the Utility’s accrued losses for the 2019 Kincade fire and the 2021 Dixie fire of $1.325 billion and $2.15 billion exceed the amounts of available liability insurance coverage of $430 million and $521 million, respectively. PG&E Corporation and the Utility could also incur substantial costs in excess of insurance coverage in connection with the 2022 Mosquito fire.
Tax The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023.
For example, the Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective for tax years beginning on or after January 1, 2023.
Under AB 1054, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Wildfire Fund reimbursement and all aspects of the reformed prudent manager standard.
Under AB 1054 and SB 254, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Continuation Account reimbursement and all aspects of the reformed prudent manager standard.
PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased and may continue to increase more quickly than expected as a result of inflation or tariffs.
PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, variable rate debt, and other inputs have increased and may continue to increase more quickly than expected as a result of inflation, import tariffs, fiscal and monetary policy, or other factors.
As of December 31, 2024, PG&E Corporation had approximately $5.65 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.5 billion aggregate principal amount of Junior Subordinated Notes due 2055, $1.0 billion aggregate principal amount of senior secured notes due 2028, and $1.0 billion aggregate principal amount of senior secured notes due 2030, and the Utility had approximately $51.9 billion of outstanding indebtedness.
As of December 31, 2025, PG&E Corporation had approximately $5.7 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.5 billion aggregate principal amount of Junior Subordinated Notes due 2055, $1.0 billion aggregate principal amount of senior secured notes due 2028, and $1.0 billion aggregate principal amount of senior secured notes due 2030, and the Utility had approximately $55.3 billion of outstanding indebtedness.
PG&E Corporation and the Utility could incur significant costs to comply with laws and regulations and be adversely affected by legislative and regulatory developments. The Utility and its operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules.
PG&E Corporation and the Utility could be adversely affected by legislative and regulatory developments, including through increased compliance costs and penalties. PG&E Corporation, the Utility, and their operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules.
For more information, see “The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire” below.
The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire.
As of December 31, 2024, the Utility has recorded probable recoveries of $602 million and $60 million for the 2021 Dixie fire and 2022 Mosquito fire, respectively, through FERC TO rates or as costs recorded to the WEMA.
As of December 31, 2025, the Utility has recorded probable recoveries of $632 million and $61 million for the 2021 Dixie fire and 2022 Mosquito fire, respectively, through FERC TO rates or as costs recorded to the WEMA.
For more information on wildfire recovery risk, see “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility may not effectively implement its wildfire mitigation initiatives.
For more information on wildfire recovery risk, see “The Wildfire Fund, Continuation Account, and other provisions of AB 1054 and SB 254 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or make other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to pay capital stock dividends or meet other obligations. 52 The Utility may be unable to manage its costs effectively.
The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or make other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to pay capital stock dividends or meet other financial obligations.
As of December 31, 2024, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $33.7 billion and $34.9 billion, respectively, and PG&E Corporation incurred and may also continue to incur significant net operating loss carryforwards and other tax attributes.
As of December 31, 2025, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $38.3 billion and $34.1 billion, respectively. PG&E Corporation may also continue to incur significant net operating loss carryforwards and other tax attributes.
Any failure, interruption, or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in a safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.
Any failure, interruption, or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in a safe and efficient manner or at all, damage the Utility’s assets or operations or those of third parties, increase costs, and impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.
In addition, there could be a significant delay between the occurrence of a wildfire and when the Utility recognizes impairment for the reduction in future coverage due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility.
In addition, there could be a significant delay between the occurrence of a wildfire and when the Utility recognizes accelerated amortization of the Wildfire Fund asset due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility.
The Utility has been and may in the future be subject to penalties or other enforcement action if a contractor violates applicable laws, rules, regulations, or orders. The Utility also has been and may be subject to liability, penalties, or other enforcement action as a result of personal injury or death caused by third-party contractor actions or inactions.
The Utility also has been and may be subject to liability, penalties, or other enforcement action as a result of personal injury or death caused by third-party contractor actions or inactions.
The Utility’s inability to service its substantial debt or access the financial markets on reasonable terms could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The documents that govern PG&E Corporation’s and the Utility’s indebtedness limit their flexibility in operating their business.
The Utility’s inability to service its substantial debt or access the financial markets on reasonable terms could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility may incur additional costs or receive reduced revenue without cost recovery for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), whether the CAISO wholesale electricity market continues to function effectively, or compliance with new state laws or policies.
Also, the CPUC may deny recovery of uninsured wildfire-related costs incurred by the Utility if the CPUC determines that the Utility was not prudent. 34 The Utility may incur additional costs or receive reduced revenue without cost recovery for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), whether the CAISO wholesale electricity market continues to function effectively, or compliance with new state laws or policies.
The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs.
Risks Related to Regulatory Proceedings, Investigations, and Enforcement Matters The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs.
If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. 45 The Utility’s operations are subject to extensive environmental laws, and such laws could change.
If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility’s environmental remediation costs could exceed its liability estimates.
As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any such incidents also could lead to significant claims against the Utility.
As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties.
PG&E Corporation and the Utility face various cybersecurity threats, including attempts to gain unauthorized access to their systems and networks, denial-of-service attacks, threats to their information technology infrastructure, ransomware and phishing attacks, and attempts to gain unauthorized access to confidential or sensitive information about the Utility, customers and employees.
PG&E Corporation and the Utility face various cybersecurity threats, including attempts to gain unauthorized access to their systems and networks, including access to confidential information about the Utility, its customers and employees, denial-of-service attacks, threats to their information technology infrastructure, ransomware, and phishing attacks. These threats come from a variety of highly organized actors, including nation-state actors.
As a capital-intensive company, the Utility relies on access to the capital markets, particularly investment grade capital markets. If the Utility were unable to access the capital markets or the cost of financing were to substantially increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
If the Utility were unable to access the capital markets or the cost of financing were to further increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors” above.
High rates could also lead to a decline in the number of customers, which could further increase rates. For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs” above.
As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Inflation and supply chain issues may adversely affect PG&E Corporation and the Utility.
As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. PG&E Corporation’s and the Utility’s substantial indebtedness may adversely affect their financial health and operating flexibility.
For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs.
The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs.
Further, the Utility has been studying the potential effects of climate change (increased severity and frequency of storm events, sea level rise, land subsidence, change in temperature extremes, changes in precipitation patterns and drought, and wildfire) on its assets, operations, and services, and the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant.
Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices or the failure of electric and other equipment of the Utility. 40 The Utility has been studying the potential effects of climate change (increased severity and frequency of storm events, sea level rise, land subsidence, change in temperature extremes, changes in precipitation patterns and drought, and wildfire) on its assets, operations, and services, and the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant.
For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event or where EPSS has been implemented on Utility equipment. The Utility’s inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues.
Wildfires can occur even when the Utility follows its procedures. For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event or where EPSS has been implemented on Utility equipment.
The Utility’s infrastructure is aging and poses risks to safety and system reliability. The Utility’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs.
The Utility may not effectively implement its wildfire mitigation initiatives. The Utility’s infrastructure is aging and poses risks to safety and system reliability. The Utility’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses.
Non-compliance with these rules could result in the imposition of material fines on PG&E Corporation and the Utility, other regulatory exposure, significant litigation, and reputational harm, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
These rules could change, which could increase the Utility’s compliance obligations and the costs to comply with these rules. Non-compliance with these rules could result in the imposition of material fines, on PG&E Corporation and the Utility, other regulatory exposure and financial risk, significant litigation, and reputational harm.
In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives.
The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities. In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives.
See “Risks Related to Wildfires” above. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions. The Utility is unable to predict the outcome of these pending or potential investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.
The Utility is unable to predict the outcome of these pending or potential investigations, including whether they will result in enforcement actions, whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations. These investigations or enforcement actions could result in a judgment against the Utility.
In addition, PG&E Corporation and the Utility had outstanding preferred stock with aggregate liquidation preferences of $1.6 billion and $258 million, respectively. Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt.
Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt.
In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes.
If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 44 In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes.
If the Utility is unable to maintain a safety certification or if the Wildfire Fund is exhausted, the ineffectiveness of the Wildfire Fund could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
If the Utility is unable to maintain a safety certification or if the Continuation Account is exhausted as a result of claims made by California’s other participating electric utility companies or otherwise, the unavailability or insufficiency of the Continuation Account could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
If the law or its interpretation is not changed to permit PG&E Corporation to deduct repairs and maintenance expense, it will incur federal cash liabilities beginning in 2027, the amount of which may become substantial in future years. See Legislative and Regulatory Initiatives in Item 8. MD&A.
If the law or its interpretation is not changed to permit PG&E Corporation to deduct repairs and maintenance expense, it will incur federal cash liabilities beginning in 2028, the amount of which may become substantial in future years. The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with regulations, which could result in penalties.
The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in litigation against PG&E Corporation or the Utility. 39 Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant.
Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant.
PG&E Corporation’s and the Utility’s recorded liabilities for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.
PG&E Corporation’s and the Utility’s recorded liability estimates for probable losses in connection with these fires do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. Similarly, PG&E Corporation’s and the Utility’s costs to resolve the Wildfire-Related Securities Claims could exceed their estimated liabilities.
If the Utility is unable to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability, its financial condition, results of operations, liquidity, and cash flows could be materially affected. 42 These industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.
If the Utility is unable to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
The Utility’s workforce is aging, and many employees are or will become eligible to retire within the next few years. The Utility’s efforts to recruit and train new field service personnel may be ineffective, and the Utility may be faced with a shortage of experienced and qualified personnel in certain specialty operational positions, such as certain positions at DCPP.
The Utility’s efforts to recruit and train new field service personnel may be ineffective, and the Utility may be faced with a shortage of experienced and qualified personnel in certain specialty operational positions, such as certain positions at DCPP. Additionally, the Utility could experience workforce disruptions as a result of labor union activity or pandemics.
PG&E Corporation, the Utility and their third-party vendors have been subject to, and will likely continue to be subject to, threats, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential or sensitive data (including information about customers and employees), or to disrupt the Utility’s operations.
PG&E Corporation, the Utility and their third-party vendors have been subject to, and will likely continue to be subject to, threats, breaches, and attempts to gain unauthorized access to the Utility’s systems and networks, which could disrupt the Utility’s operations. Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats.
PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2021 Dixie fire, or the 2022 Mosquito fire could exceed their accruals, or they could be liable as a result of future wildfires.
See “Key Factors Affecting Financial Results” and “Critical Accounting Estimates” in Item 7. MD&A. 32 PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or the Wildfire-Related Securities Claims could exceed their estimated liabilities, or they could be liable as a result of future wildfires.
The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1 above. The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities.
Risks Related to Operations and Information Technology The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks. The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1 above.
Risks Related to PG&E Corporation’s and the Utility’s Environment and Financial Condition PG&E Corporation’s and the Utility’s substantial indebtedness may adversely affect their financial health and operating flexibility. PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility.
PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility.
In addition, the Utility may be required under federal law to pay up to $332 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s DCPP facility but at any other nuclear power plant in the United States.
In addition, the Utility may be required under federal law to pay up to $332 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s DCPP facility but at any other nuclear power plant in the United States. 39 Operations at the Utility’s two nuclear generation units at DCPP could cease before their planned retirement dates in 2029 and 2030 as a result of new legislation, regulations, orders, or their interpretation, or as a result of operational costs.
See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1. 48 Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system. Jurisdictions attempt to acquire the Utility’s assets through eminent domain (“municipalization”).
Jurisdictions attempt to acquire the Utility’s assets through eminent domain, and third parties attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system. Local jurisdictions attempt to acquire some of the Utility’s assets through eminent domain (“municipalization”).
To relieve upward rate pressure, the CPUC has authorized and may in the future authorize lower revenues than the Utility requested or increase the period over which the Utility is allowed to recover amounts. The Utility’s level of authorized capital investment could decline as well, leading to fewer new business interconnections and a slower growth in rate base and earnings.
To relieve upward rate pressure on customers, the CPUC has authorized and may in the future authorize lower revenues than the Utility requested or increase the period over which the Utility is allowed to recover amounts.
Physical attacks targeting the Utility’s physical assets or personnel could cause damage, disrupt operations, or cause injuries. Cyber attacks targeting utility systems are significant and are continuing to increase in sophistication, magnitude, and frequency.
Cyber attacks targeting utility systems are significant and are continuing to increase in sophistication, magnitude, and frequency.
The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility’s ability to achieve such savings depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system.
The Utility’s ability to achieve such savings depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system, improve its work management, identify additional opportunities to convert expenses to capital expenditures, and improve organizational design.
PG&E Corporation’s and the Utility’s risk management and information security measures may be ineffective, and the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information.
The personal information that PG&E Corporation and the Utility collect, as well as other commercially-sensitive data that they possess, could nonetheless become compromised or improperly disclosed, including through the use of generative artificial intelligence or as a result of a cyber incident, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information. 35 The Utility has been and could in the future be subject to regulatory or governmental enforcement actions with respect to its compliance with such rules.
In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $3.8 billion of additional borrowing capacity under the Utility Revolving Credit Agreement and $1.5 billion under the Receivables Securitization Program.
In addition, PG&E Corporation had $650 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $3.2 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, PG&E Corporation and the Utility had outstanding preferred stock with aggregate liquidation preferences of $1.6 billion and $258 million, respectively.
Even if the Utility is able to reduce some costs, other emerging priorities, such as emergency response, public purpose programs, wildfire mitigation initiatives, or California’s clean energy transition, could require it to reinvest those savings. Concerns about high rates for the Utility’s customers could negatively impact PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Even if the Utility is able to reduce some costs through such efforts, other emerging priorities, such as emergency response, public purpose programs, wildfire mitigation initiatives, or California’s clean energy transition, could require it to reinvest those savings, which would offset the beneficial effect of such savings on net income.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changePG&E Corporation and the Utility have identified cybersecurity as a key enterprise risk, which they manage through their enterprise risk management system. PG&E Corporation and the Utility have not experienced any cybersecurity incidents in the last three years that have materially affected the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility.
Biggest changePG&E Corporation and the Utility have not experienced any cybersecurity incidents in the last three years that have materially affected, or are reasonably likely to materially affect, the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility.
For more information regarding how cybersecurity threats could materially affect PG&E Corporation and the Utility, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack.” in Item 1A.
For more information regarding how cybersecurity threats could materially affect PG&E Corporation and the Utility, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, physical attack, or technology failure” in Item 1A.
Risk Factors. 54 Governance PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, have primary responsibility for overseeing cybersecurity risk management, including reviewing the companies’ cybersecurity policies, controls, and procedures.
Risk Factors. 46 Governance PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, have primary responsibility for overseeing cybersecurity risk management, including reviewing the companies’ cybersecurity policies, controls, and procedures.
Added
PG&E Corporation and the Utility have identified cybersecurity as a key enterprise risk, which they manage through their enterprise risk management system.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeFor more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8. The Utility owns over 135,000 acres of land, including approximately 100,000 acres of watershed lands.
Biggest changeIn June 2025, the Utility closed on its acquisition of the Oakland General Office property, which serves as the headquarters of PG&E Corporation and the Utility. For more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8.
Business, under “Electric Utility Operations”, “Natural Gas Utility Operations,” and “Nuclear Operations.” The Utility occupies or uses real property primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies approximately 7.5 million square feet of real property, including 5.5 million square feet owned by the Utility.
Business, under “Electric Utility Operations”, “Natural Gas Utility Operations,” and “Nuclear Operations.” The Utility occupies or uses real property primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. Virtually all of the Utility’s plant property is subject to the lien of a first mortgage bond indenture.
Removed
Virtually all of the Utility’s plant property is subject to the lien of a first mortgage bond indenture. The Utility leases the Lakeside Building and has exercised an option to purchase the Property. The Utility will continue to lease the Property until closing in June 2025.
Removed
In 2002, the Utility agreed to implement its Land Conservation Commitment (“LCC”) to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations.
Removed
The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. In 2024, the Utility met its goal to permanently preserve the approximate 140,000 acres of watershed lands, after securing all required regulatory approvals.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeBased on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred, but the amount of the liability is not reasonably estimable. PG&E Corporation and the Utility do not believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.
Biggest changePG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. 47 Butte Canal Breach On August 9, 2023, a canal in Butte County owned by the Utility breached.
ITEM 3. LEGAL PROCEEDINGS In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see “Litigation Matters” in Item 7. MD&A, Item 1A.
ITEM 3. LEGAL PROCEEDINGS In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see “Litigation and Other Matters” in Item 7. MD&A, Item 1A.
Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
PG&E Corporation and the Utility do not believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.
Each of PG&E Corporation and the Utility has elected use $1 million as the quantitative threshold for disclosure of environmental proceedings described in Item 103(c)(3)(iii) of Regulation S-K. 55 CZU Lightning Complex Fire Notices of Violation Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and the Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations.
CZU Lightning Complex Fire Notices of Violation Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and the Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations.
Butte Canal Breach On August 9, 2023, a canal in Butte County owned by the Utility breached. The Central Valley Regional Water Quality Control Board has alleged environmental violations in connection with the breach. Violations can result in penalties, remediation, and other relief.
The Central Valley Regional Water Quality Control Board has alleged environmental violations in connection with the breach. Violations can result in penalties, remediation, and other relief. Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred, but the amount of the liability is not reasonably estimable.
Risk Factors and Notes 9, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8 .
Risk Factors and Notes 9, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8 . SEC rules require disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the company reasonably believes will exceed a specified threshold.
Added
Consistent with SEC rules, each of PG&E Corporation and the Utility has elected to use $1 million as the quantitative threshold for disclosure of such proceedings.
Added
Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

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Biggest changeSeptember 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 Ajay Waghray 63 Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2024 to present Executive Vice President and Chief Information Officer, PG&E Corporation July 1, 2023 to December 31, 2023 Senior Vice President and Chief Information Officer September 21, 2020 to June 30, 2023 Founder, Agni Growth Ventures, LLC January 2019 to September 2021 Executive Vice President and Chief Technology Officer, Assurant Inc.
Biggest changeVallejo 49 PG&E Corporation, Utility Executive Vice President, Chief People Officer, PG&E Corporation and Utility September 2025 to present Chief Risk Officer and Senior Vice President, Ethics and Compliance, PG&E Corporation and Utility August 2023 to September 2025 Vice President, Compliance and Ethics, and Deputy General Counsel, Utility December 2020 to July 2023 Ajay Waghray 64 PG&E Corporation, Utility Executive Vice President and Chief Information Officer, PG&E Corporation and Utility January 2024 to present Executive Vice President and Chief Information Officer, PG&E Corporation July 2023 to December 2023 Senior Vice President and Chief Information Officer, PG&E Corporation September 2020 to June 2023 Stephanie N.
Peterman 46 Executive Vice President, Corporate Affairs and Chief Sustainability Officer October 1, 2021 to present Executive Vice President, Corporate Affairs June 2021 to September 2021 Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison September 2019 to May 2021 Commissioner, California Public Utilities Commission December 2012 to December 2018 Marlene M.
Peterman 47 PG&E Corporation President, PG&E Corporation, and Executive Vice President, Customer and Corporate Affairs, PG&E Corporation January 2026 to present Executive Vice President, Corporate Affairs and Chief Sustainability Officer, PG&E Corporation October 2021 to December 2025 Executive Vice President, Corporate Affairs, PG&E Corporation June 2021 to September 2021 Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison Company September 2019 to May 2021 48 Commissioner, California Public Utilities Commission December 2012 to December 2018 Marlene M.
Williams 42 Vice President, Chief Financial Officer and Controller January 10, 2023 to present Vice President and Controller, PG&E Corporation January 10, 2023 to present Vice President, Finance and Planning January 2020 to January 10, 2023 Senior Director, Business Finance Electric Operations March 2019 to January 10, 2022 Director, Business Finance October 2014 to February 2019 Kaled H.
Williams 43 Utility Vice President, Chief Financial Officer and Controller, Utility January 2023 to present 49 Vice President and Controller, PG&E Corporation January 2023 to present Vice President, Finance and Planning, Utility January 2020 to January 2023 Senior Director, Business Finance Electric Operations, Utility March 2019 to December 2019 50 PART II
Glickman 44 Executive Vice President, Engineering, Planning, and Strategy, Pacific Gas and Electric Company May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Consultant, Bain & Company August 2007 to December 2013 Carla J.
Glickman 45 PG&E Corporation, Utility Executive Vice President, Strategy and Growth, PG&E Corporation and Utility January 2026 to present Executive Vice President, Engineering, Planning, and Strategy, Utility May 2021 to December 2025 Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Carla J.
March 2015 to December 2018 Sumeet Singh 46 Executive Vice President, Operations and Chief Operating Officer March 1, 2023 to present Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to February 28, 2023 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
Simon 61 PG&E Corporation Executive Vice President, General Counsel and Chief Ethics & Compliance Officer, PG&E Corporation August 2020 to present Sumeet Singh 47 PG&E Corporation, Utility Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery, Utility January 2026 to present Executive Vice President, Operations and Chief Operating Officer, Utility March 2023 to December 2025 Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Utility January 2022 to February 2023 Senior Vice President and Chief Risk Officer, PG&E Corporation and Utility February 2021 to December 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 2021 to January 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Utility August 2020 to December 2021 Alejandro T.
Poppe 56 Chief Executive Officer January 4, 2021 to present President and Chief Executive Officer, CMS Energy Corporation July 2016 to December 2020 Vice President, Customer Experience, Rates and Regulations, Consumers Energy Company January 2011 to July 2016 Carolyn J.
Poppe 57 PG&E Corporation Chief Executive Officer, PG&E Corporation January 2021 to present President and Chief Executive Officer, CMS Energy Corporation July 2016 to December 2020 Carolyn J.
ITEM 4. MINE SAFETY DISCLOSURES Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following individuals serve as executive officers of PG&E Corporation, as of February 12, 2025. Except as otherwise noted, all positions have been held at PG&E Corporation. Name Age Positions Held Over Last Five Years Time in Position Patricia K.
ITEM 4. MINE SAFETY DISCLOSURES Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following individuals serve as executive officers of PG&E Corporation and the Utility (as applicable), as of February 11, 2026. Name Age Entity At Which Officer is an Executive Officer Title Time in Position Patricia K.
Santos 64 Executive Vice President and Chief Customer and Enterprise Solutions Officer October 16, 2023 to present Executive Vice President and Chief Customer Officer March 15, 2021 to October 15, 2023 President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc.
Santos 65 PG&E Corporation, Utility Executive Vice President, Enterprise Transformation Officer, PG&E Corporation and Utility January 2026 to present Executive Vice President and Chief Customer and Enterprise Solutions Officer, Utility October 2023 to December 2025 Executive Vice President and Chief Customer Officer, Utility March 2021 to October 2023 President, Gulf Power Company January 2019 to March 2021 John R.
Burke 57 Executive Vice President and Chief Financial Officer May 4, 2023 to present Chief Financial Officer & Executive Vice President, Chevron Phillips Chemical Company LLC February 2019 to September 2022 Senior positions, including Executive Vice President, Strategy & Administration, Dynegy, Inc. August 2011 to April 2018 Kaled H.
Burke 58 PG&E Corporation Executive Vice President and Chief Financial Officer, PG&E Corporation May 2023 to present Chief Financial Officer & Executive Vice President, Chevron Phillips Chemical Company LLC February 2019 to September 2022 Jason M.
Removed
Awada 50 Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company January 16, 2024 to present Executive Vice President & Chief Human Resources Officer, Tenneco Inc. September 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 56 Jason M.
Removed
Santos 64 Executive Vice President and Chief Customer and Enterprise Solutions Officer, Pacific Gas and Electric Company October 16, 2023 to present Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company March 15, 2021 to October 15, 2023 President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc.
Removed
Simon 60 Executive Vice President, General Counsel and Chief Ethics & Compliance Officer August 15, 2020 to present Executive Vice President, Law, Strategy, and Policy June 2019 to August 2020 Executive Vice President May 2019 to June 2019 Interim Chief Executive Officer January 2019 to May 2019 Executive Vice President and General Counsel March 2017 to January 2019 Executive Vice President, Corporate Services and Human Resources August 2015 to February 2017 Sumeet Singh 46 Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company March 1, 2023 to present Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to February 28, 2023 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
Removed
February 2020 to August 2020 57 Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018 September 2015 to January 2020 Ajay Waghray 63 Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2024 to present Executive Vice President and Chief Information Officer, PG&E Corporation July 1, 2023 to December 31, 2023 Senior Vice President and Chief Information Officer September 21, 2020 to June 30, 2023 Founder, Agni Growth Ventures, LLC January 2019 to September 2021 Executive Vice President and Chief Technology Officer, Assurant Inc.
Removed
May 2016 to December 2018 58 The following individuals serve as executive officers of the Utility as of February 12, 2025. Except as otherwise noted, all positions have been held at the Utility. Jason M.
Removed
Glickman 44 Executive Vice President, Engineering, Planning, and Strategy May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Consultant, Bain & Company August 2007 to December 2013 Marlene M.
Removed
February 2020 to August 2020 Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018 September 2015 to January 2020 Stephanie N.
Removed
Awada 50 Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company January 16, 2024 to present 59 Executive Vice President & Chief Human Resources Officer, Tenneco Inc.
Removed
May 2016 to December 2018 60 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES As of February 5, 2025, there were 40,511 holders of record of PG&E Corporation common stock.
Biggest changeITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES As of February 4, 2026, there were 38,490 holders of record of PG&E Corporation common stock.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changePartially offset by: • approximately $390 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in 2024; • 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; • approximately $175 million in revenues authorized in the GOSMA petition for modification final decision in 2024 with no similar amount in 2023; • approximately $170 million in interim rate relief authorized in the 2023 WMCE application (see “2023 WMCE Application” below) in 2024 with no similar amount in 2023; • the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in 2024; and • an increase in labor and benefit costs in 2024.
Biggest changeThe 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 56 • 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.
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.
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.
The Utility’s undiscounted future costs could increase to as much as $2.3 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements.
The Utility’s undiscounted future costs could increase to as much as $2.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements.
LIQUIDITY AND FINANCIAL RESOURCES Overview PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term. 67 PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs.
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 approval is subject to the following conditions: (1) the NRC continues to authorize DCPP operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that DCPP extended operations are imprudent or unreasonable.
The CPUC’s approval is subject to the following conditions: (1) the NRC continues to authorize DCPP operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that DCPP extended operations are imprudent or unreasonable.
The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following proceedings.
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.
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 credit rating from each of the major credit rating agencies.
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.
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.
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.
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
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.
SB 884 10-Year Distribution Undergrounding Program On March 7, 2024, the CPUC approved a resolution that establishes 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.
SB 884 10-Year Distribution Undergrounding Program On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed 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.
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 CEMA.
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.
See Item 1A. Risk Factors, “Environmental Regulation” in Item 1 and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. RISK MANAGEMENT ACTIVITIES PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.
See Item 1A: “Risk Factors,” “Environmental Regulation” in Item 1 and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. RISK MANAGEMENT ACTIVITIES PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.
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, and regulatory 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.
Additionally, due to its existing tax attributes, PG&E Corporation does not expect to pay significant federal cash taxes until at least 2029. In 2024, California enacted a new law to suspend the use of net operating losses and limit the use of business credits for tax years 2024 to 2026.
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.
The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. PG&E Corporation uses value-at-risk to measure its shareholders’ exposure to these risks. The value-at-risk was approximately $5 million and $4 million at December 31, 2024 and 2023, respectively.
The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. PG&E Corporation uses value-at-risk to measure its shareholders’ exposure to these risks. The value-at-risk was approximately $4 million and $5 million at December 31, 2025 and 2024, respectively.
Management’s Discussion and Analysis of Financial Condition and Results of Operations in PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC in February 2024.
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.
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. 63 RESULTS OF OPERATIONS The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2024 and 2023.
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.
The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables.
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.
The costs addressed in this 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.
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.
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.
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.
Enforcement and Litigation Matters PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.
At December 31, 2024 and 2023, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $6 million and $57 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
At December 31, 2025 and 2024, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term borrowings, and cash investments, the pre-tax impact on net income over the next 12 months would be $37 million and $6 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
Future cash flow from operating activities will be affected by various factors, including: • the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries; • the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8); • the timing and amount of costs in connection with the 2023-2025 WMP and the portion of the costs previously incurred in connection with the 2020-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information); • the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and • the timing and amount of electric commodity price volatility and differences between commodity costs and revenue collections.
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.
For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain.
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.
As of December 31, 2024, PG&E Corporation and the Utility remain in compliance with all financial covenants. 68 Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.
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.
The discussion related to the results of operations and liquidity for 2023 compared to 2022 is incorporated by reference to Part II, Item 7.
The discussion related to the results of operations and liquidity for 2024 compared to 2023 is incorporated by reference to Part II, Item 7.
These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8.
In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2024, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.
In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2025, the SB 901 regulatory asset was approximately $5.1 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.
PG&E Corporation’s and the Utility’s Amended and Restated Articles of Incorporation, each filed on June 22, 2020, and for PG&E Corporation, as amended by the 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.
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.
For example, based on the closing prices of PG&E Corporation’s common stock and preferred stock as of February 5, 2025, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 5, 2025 was 3.92% of the combined value of PG&E Corporation’s outstanding common and preferred stock.
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 following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: Exposure (1) (in millions) Number of Wholesale Customers or Counterparties >10% Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions) December 31, 2024 $ 1,114 4 $ 708 December 31, 2023 $ 926 3 $ 457 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties.
The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: Exposure (1) (in millions) Number of Wholesale Customers or Counterparties >10% Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions) December 31, 2025 $ 1,048 4 $ 714 December 31, 2024 $ 1,114 4 $ 708 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties.
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.
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.
During the years ended December 31, 2024 and 2023, the Utility recorded amortization and accretion expense of $383 million and $567 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income.
During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $352 million and $383 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income.
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.
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. 62 In recent years, the Utility has recorded significant amounts to these accounts.
In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2025 was 7.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2033 and beyond.
In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2026 was 7.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2036 and beyond.
LITIGATION MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and in “Regulatory Matters” below that are incorporated by reference herein.
LITIGATION AND OTHER MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 and in “Regulatory Matters” above that are incorporated by reference herein.
As of December 31, 2024, a 5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by five years assuming greater effectiveness and would decrease the amortization period by five years assuming less effectiveness.
As of December 31, 2025, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by ten years assuming greater effectiveness and would decrease the amortization period by five years assuming less effectiveness.
As a result, PG&E Corporation expects to pay state income taxes in 2025 and 2026. See “Tax Matters” above and “Inflation Reduction Act” in Legislative and Regulatory Initiatives below for a discussion of events that could limit PG&E Corporation’s ability to use its net operating losses. PG&E Corporation and the Utility have various contractual commitments which impact cash requirements.
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.
Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2024, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $23.8 billion.
Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2025, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $22.6 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $24.3 billion.
See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information. 62 • The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business.
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. 52 • The Timing and Outcome of Ratemaking Proceedings, Other Proceedings, and Legislation. Regulatory ratemaking proceedings are a key aspect of the Utility’s business.
These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs.
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.
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.
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.
For the Utility’s defined benefit pension plan, the assumed return of 6.4% compares to a ten-year actual return of 5.1%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 858 Aa-grade non-callable bonds at December 31, 2024.
For the Utility’s defined benefit pension plan, the assumed return of 7.0% compares to a ten-year actual return of 5.7%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 831 Aa-grade non-callable bonds at December 31, 2025.
See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning.
See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and estimated decommissioning dates.
Restrictive Debt Covenants PG&E Corporation’s and the Utility’s credit agreements and the DOE Loan Guarantee Agreement contain various restrictive financial covenants, including a financial covenant requiring PG&E Corporation and the Utility to maintain a total consolidated debt to total consolidated capitalization ratio of no more than 70% and 65% for PG&E Corporation and the Utility, respectively, as of the end of each fiscal quarter.
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.
In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening (such as undergrounding).
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.
For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors and “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.
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.
Accordingly, although PG&E Corporation had 2,671,320,389 common shares outstanding as of February 5, 2025, only 2,193,576,799 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.
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.
See Note 12 of the Notes to the Consolidated Financial Statements in Item 8. 87 In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term.
In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term.
These liability amounts correspond to the lower end of the range of reasonably estimable probable 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, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries.
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.
As of December 31, 2024, the Utility has recorded receivables for regulatory recovery of $602 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire.
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.
Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. The Utility has recorded an aggregate Wildfire Fund receivable of $925 million for the 2021 Dixie fire, of which it had received $169 million as of December 31, 2024.
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.
As of December 31, 2024, PG&E Corporation and the Utility had access to approximately $6.7 billion of total liquidity comprised of $705 million of the Utility’s Cash and cash equivalents, $235 million of PG&E Corporation’s Cash and cash equivalents and $5.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.
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.
While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses.
While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.
Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $33.7 billion and a California net operating loss carryforward of approximately $34.9 billion as of December 31, 2024.
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.
On January 27, 2025, the Utility filed an application for rehearing. 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”).
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”).
See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates. 82 Energy Procurement Credit Risk The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada.
Energy Procurement Credit Risk The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada.
As of December 31, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $564 million in Other noncurrent liabilities, $301 million in Current assets - Wildfire Fund asset, and $4.1 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets.
As of December 31, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $377 million in Other noncurrent liabilities, $297 million in Current assets - Wildfire Fund asset, and $3.7 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets.
CRITICAL ACCOUNTING ESTIMATES The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Exposure amounts reported above do not include adjustments for time value or liquidity. 69 CRITICAL ACCOUNTING ESTIMATES The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The CPUC’s procedural schedule indicates a final decision by the second quarter of 2025. 77 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 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”).
While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. 86 Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (“CHT”).
Additionally, SB 901 provides a mechanism for the CPUC to allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (“CHT”).
See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility will be permitted to recover its wildfire-related claims in excess of available insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard.
The 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 Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.
The 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. 57 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.
The following table provides a summary of income (loss) attributable to common shareholders: (in millions) 2024 2023 Consolidated Total $ 2,475 $ 2,242 PG&E Corporation (223) (288) Utility 2,698 2,530 PG&E Corporation’s net loss primarily consists of interest expense on long-term debt. Utility The table below shows the Utility’s Consolidated Statements of Income for 2024 and 2023.
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. 54 Utility The table below shows the Utility’s Consolidated Statements of Income for 2025 and 2024.
The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses).
The 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.
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. 71 Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund.
Commodity Price Risk The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers.
The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. 68 Commodity Price Risk The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers.
If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount.
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.
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.
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 December 2024, PG&E Corporation announced a new dividend policy entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors.
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.
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.
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.
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. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.
The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 2024 2023 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) (0.8) % (34.4) % Effect of regulatory treatment of fixed asset differences (2) (24.7) % (40.1) % Tax credits (0.7) % (2.2) % Fire Victim Trust (3) — % (80.2) % Other, net 1.2 % 1.1 % Effective tax rate (4.0) % (134.8) % (1) Includes the effect of state flow-through ratemaking treatment.
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.
The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes.
The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.
The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2024 Pension Costs Increase in Projected Benefit Obligation at December 31, 2024 Discount rate (0.50) % $ (1) $ 1,093 Rate of return on plan assets (0.50) % 85 — Rate of increase in compensation 0.50 % 30 250 The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2024 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2024 Health care cost trend rate 0.50 % $ 6 $ 37 Discount rate (0.50) % 6 78 Rate of return on plan assets (0.50) % 12 — ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.
The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. 73 The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2025 Pension Costs Increase in Projected Benefit Obligation at December 31, 2025 Discount rate (0.50) % $ 13 $ 1,148 Rate of return on plan assets (0.50) % 82 — Rate of increase in compensation 0.50 % 35 267 The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2025 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2025 Health care cost trend rate 0.50 % $ 6 $ 41 Discount rate (0.50) % 6 89 Rate of return on plan assets (0.50) % 12 — ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.
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, and the timing and terms of other financings. Debt Financings Utility The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.
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.
Transmission Owner Rate Cases Transmission Owner Rate Case for 2024 (the “TO21” rate case) On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasted a 2024 retail electric transmission revenue requirement of $2.83 billion.
Transmission Owner Rate Case for 2024 On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasted a 2024 retail electric transmission revenue requirement of $2.83 billion. The Utility requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO.
Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s credit rating remains below investment grade, the Utility generally does not receive unsecured credit from its energy procurement counterparties and it may be required to increase its collateral postings if its credit rating is downgraded.
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.
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.
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. 53 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.
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.
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. 60 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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 88
Biggest changeITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 74

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