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What changed in PG&E Corporation's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of PG&E Corporation's 2023 and 2024 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 2024 report.

+590 added−665 removedSource: 10-K (2025-02-13) vs 10-K (2024-02-22)

Top changes in PG&E Corporation's 2024 10-K

590 paragraphs added · 665 removed · 444 edited across 9 sections

Item 1. Business

Business — how the company describes what it does

141 edited+36 added−43 removed155 unchanged
Biggest changeAs a result of actions already taken by PG&E Corporation and the Utility, the companies have: • Delivered electricity to customers in 2023 that was 100% 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 3.5 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 550,000; installed more than 475 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and launched a first of its kind vehicle-to-grid program enabling customers to leverage their electric vehicles to power their home. • Brought the total number of interconnected private solar customers to more than 800,000 and supported more than 70,000 customers who have installed battery storage at their homes or businesses. • 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 and accelerated initiatives to meet its voluntary 2030 reduction goal.
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.
The Utility’s commitment to increasing resilience to climate change includes aligning its resources and business strategy with California’s clean energy goals, the Utility’s climate strategy, and advocating for policies and programs that enable safe and reliable energy for the Utility’s customers in light of climate change.
The Utility’s commitment to increasing resilience to climate change includes aligning its resources and business strategy with California’s clean energy goals, and advocating for policies and programs that enable safe and reliable energy for the Utility’s customers in light of climate change.
Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain 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.
The Utility conducts an annual employee survey to measure and improve employee engagement. 27 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 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 triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities. 11 PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions.
The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities. PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions.
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 (“cost-of-service ratemaking”).
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.
The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with adjustments for under-collections and over-collections made in subsequent monthly rate changes. The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.
The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with adjustments for under-collections and over-collections made in subsequent monthly rate changes. 23 The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.
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.
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.
As a result, the Utility could lose customers (residential, commercial, and industrial) or experience limited growth in the municipality. See “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain, and third parties may 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 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.
Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. 34 The Utility is also impacted by an increasing quantity of distributed generation and energy storage.
Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. The Utility is also impacted by an increasing quantity of distributed generation and energy storage.
The FERC’s approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property.
The FERC’s approval is required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property.
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.
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.
Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO. 31 Electricity Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to customers.
Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO. Electricity Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to customers.
The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers. The cap-and-trade program applies to the electric generation, large industrial, natural gas, petroleum, and transportation sectors.
The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers. The cap-and-trade program applies to the electric generation, large industrial, natural gas, and transportation sectors.
State Regulation California laws and regulations have established the following targets: • A 40% reduction in GHGs by 2030 compared to 1990 levels. • 50% of retail energy sales to customers from renewable energy sources by 2026 and 60% by 2030. • Economy-wide State carbon neutrality by 2045, with net negative emissions thereafter. • Renewable and zero-carbon resources supplying 90% of utilities’ retail sales to customers by 2035, 95% by 2040, and 100% by 2045.
Greenhouse Gas Emissions Regulation California laws and regulations have established the following targets: • A 40% reduction in GHGs by 2030 compared to 1990 levels. • 50% of retail energy sales to customers from renewable energy sources by 2026 and 60% by 2030. • Economy-wide State carbon neutrality by 2045, with net negative emissions thereafter. • Renewable and zero-carbon resources supplying 90% of utilities’ retail sales to customers by 2035, 95% by 2040, and 100% by 2045.
Diablo Canyon Extended Operations During the period of extended operations and in lieu of the traditional rate-based return on investment, SB 846 provides for a fixed payment of $50 million, in 2022 dollars, for each of Diablo Canyon’s Unit 1 and Unit 2 for each year of extended operations to be recovered from customers of all CPUC-jurisdictional LSEs, which is potentially subject to adjustment downward in the event of extended unplanned outages.
Diablo Canyon Extended Operations During the period of extended operations and in lieu of the traditional rate-based return on investment, SB 846 provides for a fixed payment of $50 million, in 2022 dollars, for each of DCPP’s Unit 1 and Unit 2 for each year of extended operations to be recovered from customers of all CPUC-jurisdictional LSEs, which is potentially subject to adjustment downward in the event of extended unplanned outages.
Triple Bottom Line PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the difficulties many coworkers face in their day-to-day work, and deliver better outcomes for customers and communities.
Triple Bottom Line PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the difficulties many employees face in their day-to-day work, and deliver better outcomes for customers and communities.
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 workers 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 senior leadership.
For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A. 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 the TO rate case.
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.
The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service area through a competitive bidding process managed by the CAISO. For risks in connection with increasing competition, see Item 1A. Risk Factors.
The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service area through a competitive bidding process managed by the CAISO. For risks in connection with increasing competition, see Item 1A.
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 penetration 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 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.
The following table shows the Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2022, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.
The following table shows the Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2023, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.
Of the Utility’s regular employees, approximately 17,000 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 17,600 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”).
In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for wildfire risk reduction when needed and enhancing reliability when wildfire risk is low.
The Utility also uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for wildfire risk reduction when needed and enhancing reliability when wildfire risk is low.
Air Quality and Climate Change 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.
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.
In 2023, the Utility significantly expanded its 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.
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.
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 customers in 2023 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. 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.
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, coworkers, 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.
Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s independent spent fuel storage installation at Humboldt Bay. See “Electricity Resources” below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities.
Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at DCPP and the Utility’s independent spent fuel storage installation at Humboldt Bay. See “Electricity Resources” below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities.
Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits (e.g., credits for GHG reductions achieved by third parties, such as landowners, livestock owners, and farmers, that occur outside of the entities’ facilities through CARB-qualified offset projects such as reforestation or biomass projects).
Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits (e.g., credits for GHG reductions achieved by third parties, such as landowners, livestock owners, and farmers, that occur outside of the entities’ facilities through CARB-qualified offset projects such as reforestation or methane capture projects).
The Utility files an application with the CPUC 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 plants. 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. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers.
(PG&E Corporation and the Utility define retirement age as 55 years and older.) The Utility’s contractors and subcontractors include approximately 30,000 individuals from approximately 1,000 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 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.
In addition, SB 846 authorizes a volumetric payment totaling $13 (in 2022 dollars) for each MWh generated by Diablo Canyon during the period of extended operations, with the first half recovered from all CPUC-jurisdictional LSEs and the second half from customers in the Utility’s service area.
In addition, SB 846 authorizes a volumetric payment totaling $13 (in 2022 dollars) for each MWh generated by DCPP during the period of extended operations, with the first half recovered from all CPUC-jurisdictional LSEs and the second half from customers in the Utility’s service area.
The worsening conditions across California increase the likelihood and severity of wildfires, including those where the Utility’s equipment may be alleged to be associated with the fire’s ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility.
The worsening conditions across California increase the likelihood and severity of wildfires, including those in which the Utility’s equipment may be alleged to be associated with the fire’s ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility.
The amount of the fixed and volumetric payments will be adjusted annually by the CPUC using CPUC-approved escalation methodologies and adjustment factors. The volumetric payment cannot be realized as shareholder profits or paid out as dividends, to the extent it is not needed for Diablo Canyon.
The amount of the fixed and volumetric payments will be adjusted annually by the CPUC using CPUC-approved escalation methodologies and adjustment factors. The volumetric payment cannot be realized as shareholder profits or paid out as dividends, to the extent it is not needed for DCPP.
The CARB plans to update the cap-and-trade regulation in 2024 and is considering reforms that would reduce overall allowance budgets to align with CARB’s 2022 Climate Change Scoping Plan. 20 During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year.
The CARB plans to update the cap-and-trade regulation in 2025 and is considering reforms that would reduce overall allowance budgets to align with CARB’s 2022 Climate Change Scoping Plan. 34 During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year.
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.
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.
Like NEM customers, customers interconnecting on the NBT, are required to pay an interconnection fee, utilize time of use rates, and pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.
NEM and NBT customers are required to pay an interconnection fee, utilize time of use rates, and pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.
Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation. If it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued.
Under the gas and electric citation programs adopted by the CPUC, the SED has discretion whether to issue a penalty for each violation. If it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued.
As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel.
As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at DCPP and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel.
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, 2023, PG&E Corporation had 10 employees and the Utility had approximately 28,000 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. 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.
As the Utility’s asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions 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 conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground.
Risk Factors and “Regulatory Matters - OIR to Revisit Net Energy Metering Tariffs” in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers, in some cases bypassing the Utility’s electric infrastructure entirely.
Risk Factors and “Regulatory Matters - Order Instituting Rulemaking (“OIR”) to Revisit Net Energy Metering Tariffs” in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers, in some cases bypassing the Utility’s electric infrastructure entirely.
The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay.
The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at DCPP and the retired nuclear facility at Humboldt Bay.
The IBEW, ESC, and SEIU represent approximately 63% of the Utility’s employee workforce and support several areas of the Utility’s business, including gas and electric operations. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2023. PG&E Corporation’s employees are primarily at the executive management level.
The IBEW, ESC, and SEIU represent approximately 62% of the Utility’s employee workforce and support several areas of the Utility’s business, including gas and electric operations. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2024. 24 PG&E Corporation’s employees are primarily at the executive management level.
All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.
All of the Utility’s powerhouses are licensed by the FERC (except for one small powerhouse not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.
The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See “Environmental Regulation - Air Quality and Climate Change” below.
The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See “Environmental Regulation - Air Quality and the Clean Air Act” below.
When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. More than 96% of core customers, representing approximately 84% of the annual core market demand, receive bundled natural gas service from the Utility.
When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. More than 97% of core customers, representing approximately 85% of the annual core market demand, receive bundled natural gas service from the Utility.
These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO 2 ), sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), particulate matter, and other emissions. Federal Regulation At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act.
These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO 2 ), sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), particulate matter, and other emissions. At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act, which it uses to address GHG emissions.
The successor to the NEM tariffs, the NBT, will provide bill credits at a lower rate, which reduces the level of upward rate pressure on non-NEM or non-NBT customers, but does not eliminate such upward rate pressure.
The successor to the NEM tariffs, the NBT provides bill credits at a lower rate, which reduces the level of upward rate pressure on non-NEM or non-NBT customers, but does not eliminate the upward rate pressure.
The Utility has set a goal to increase customer capital investments while also limiting customer bill impacts, including by achieving operating cost savings and by seeking efficient financing. The Utility plans to meet its cost reduction goal through increased efficiencies, including waste elimination through the Lean operating system.
The Utility has set a goal to increase customer capital investments while also limiting customer bill impacts, including by achieving operating cost savings, seeking efficient financing, and benefiting from electric load growth. The Utility plans to meet its cost savings goal through increased efficiencies including waste elimination through the Lean operating system.
For example, the Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected increases in demand for electricity.
For example, the Utility believes its strategies to reduce GHG emissions through a portfolio of customer programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected increases in demand for electricity.
The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its CPIM described below.
The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its Core Procurement Incentive Mechanism (“CPIM”) described below.
During 2023, the Utility purchased approximately 299,000 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 54% of the total natural gas volume the Utility purchased during 2023.
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.
For more information about Diablo Canyon, see Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Other Regulators The CEC is a California agency with responsibility for energy policy and planning. The CEC is responsible for licensing all thermal power plants over 50 MW within California.
Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Other Regulators The CEC is a California agency with responsibility for energy policy and planning. The CEC is responsible for licensing all thermal power plants over 50 MW within California.
In 2022, the Utility spent $4.79 billion with certified diverse suppliers, representing 39.3% of its total spend. 14 Performance: Underpinning the Triple Bottom Line PG&E Corporation and the Utility use the Lean operating system, which includes five basic “plays”: visual management; operating reviews; problem solving; standard work; and waste elimination.
In 2023, the Utility spent $4.18 billion with certified diverse suppliers, representing 36.6% of its total spend. Performance: Underpinning the Triple Bottom Line PG&E Corporation and the Utility use the Lean operating system, which includes five basic “plays”: visual management; operating reviews; problem solving; standard work; and waste elimination.
Planet The planet element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations.
For more information, see “Human Capital” below. Planet The planet element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations.
The Utility plans to keep the Los Medanos storage field in operation 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 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.
Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads.
Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads. Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating.
The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. In 2023, the Utility undergrounded 364 miles of lines, nearly double the number of miles undergrounded in 2022.
The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. In 2024, the Utility undergrounded 259 miles of lines.
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.
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.
Finally, the Utility is soliciting 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2026 and 2028.
Separately, the Utility is soliciting long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2028 and 2031.
In 2023, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools. 33 Natural Gas Operating Statistics The following table shows the Utility’s operating statistics from 2021 through 2023 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.
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.
PG&E Corporation’s and the Utility’s financial incentives offered to employees include a Short-Term Incentive Plan (“STIP”), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2023 STIP was focused on company objectives of safety, customer impact, and financial health. All PG&E Corporation and Utility officer compensation currently is funded by shareholders.
PG&E Corporation’s and the Utility’s financial incentives offered to employees include a Short-Term Incentive Plan (“STIP”), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2024 STIP was focused on company objectives of safety, customer impact, and financial health.
The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.
See “Sustainability and Resiliency” below. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets. The Utility expects that these costs will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.
Models incorporating future temperature and precipitation projections suggest that landscape susceptibility to wildfire within the Utility’s service area will continue to increase over time, with an expansion of areas that may become HFTD and an intensification of risk within HFTDs.
Climate change will also continue to intensify the potential for wildfires throughout California. Models incorporating future temperature and precipitation projections suggest that landscape susceptibility to wildfire within the Utility’s service area will continue to increase over time, with an expansion of areas that may become HFTD and an intensification of risk within HFTDs.
(3) These amounts represent revenues authorized to be billed. 32 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.
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.
In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated that the Utility incur substantial costs at Diablo Canyon, and substantial costs could be required in the future.
In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated that the Utility incur substantial costs at DCPP, and substantial costs could be required in the future. For more information about DCPP, see Item 1A.
The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations.
The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations. These wholesale customers are charged individualized rates based on the terms of their contracts.
The Utility’s total capital expenditures (including accruals) are forecasted to be $10.4 billion for 2024, $12.7 billion for 2025, $11.5 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 $12.9 billion for 2025, $12.0 billion for 2026, $13.6 billion for 2027, and $14.0 billion for 2028.
In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility’s owned and operated gas storage fields, Pleasant Creek and Los Medanos. The Utility expects to close on the sale of Pleasant Creek in 2024.
In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility’s owned and operated gas storage fields, Pleasant Creek and Los Medanos. The sale of Pleasant Creek is currently pending CPUC review and approval and the Utility anticipates to close on the sale in 2025.
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 issued on November 17, 2023, and expenditures to be included in a later filing or separate applications.
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.
(2) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(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.
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. 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”).
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. At December 31, 2023, the Utility’s natural gas system consisted of approximately 44,200 miles of distribution pipelines, over 6,400 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, 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.
The Utility generally has a stable workforce. The Utility’s turnover rates for 2023 and 2022 were 4.0% and 7.1%, respectively. Approximately 42% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 18% of PG&E Corporation’s and the Utility’s employees are eligible to retire.
The Utility generally has a stable workforce. The Utility’s turnover rate for each of 2024 and 2023 was 4.0%. Approximately 44% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 18% of PG&E Corporation’s and the Utility’s employees are eligible to retire.
No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2023, 2022 or 2021. 2023 2022 2021 Customers (average for the year) (1) 4,605,628 4,585,126 4,563,747 Gas purchased (MMcf) 239,756 227,128 226,037 Average price of natural gas purchased (price per Mcf) $ 6.91 $ 7.42 $ 3.19 Bundled gas sales (MMcf): Residential 171,889 160,449 162,205 Commercial 60,248 57,066 54,262 Total Bundled Gas Sales 232,137 217,515 216,467 Revenues (in millions): Bundled gas sales: Residential $ 3,686 $ 3,353 $ 2,759 Commercial 1,052 1,005 713 Other (145) 163 140 Bundled gas revenues 4,593 4,521 3,612 Transportation service only revenue 1,603 1,534 1,346 Subtotal 6,196 6,055 4,958 Regulatory balancing accounts (2) 808 565 553 Total operating revenues $ 7,004 $ 6,620 $ 5,511 Selected Statistics: Average annual residential usage (Mcf) 37 37 37 Average billed bundled gas sales revenues per Mcf: Residential $ 20.73 $ 20.22 $ 16.54 Commercial 14.99 15.19 11.63 Net plant investment per customer $ 4,749 $ 4,522 $ 4,130 (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 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.
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 2022. This resulted in a third-party verified CO 2 emissions rate of 56 pounds of CO 2 per MWh.
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.
No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2023, 2022 or 2021. 2023 2022 2021 Customers (average for the year) 5,584,185 5,562,223 5,539,969 Deliveries (in GWh) (1) 72,933 77,769 78,588 Revenues (in millions): Residential $ 6,041 $ 6,130 $ 6,089 Commercial 5,643 5,416 5,042 Industrial 1,784 1,626 1,493 Agricultural 1,413 1,830 1,565 Public street and highway lighting 83 77 73 Other, net (2) 136 (247) (84) Subtotal 15,100 14,832 14,178 Regulatory balancing accounts (3) 2,324 228 953 Total operating revenues $ 17,424 $ 15,060 $ 15,131 Selected Statistics: Average annual residential usage (kWh) 5,217 5,564 5,889 Average billed revenues per kWh: Residential $ 0.2356 $ 0.2253 $ 0.2125 Commercial 0.2007 0.1896 0.1802 Industrial 0.1294 0.1177 0.1075 Agricultural 0.2984 0.2435 0.2104 Net plant investment per customer $ 10,720 $ 9,967 $ 9,199 (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 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.
The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.
The Utility also operated 33 electric transmission substations with a capacity of approximately 67,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeAny 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. 41 The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals, and portions of such sensitive information may be required to be encrypted by the Utility.
Biggest changeThe Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store, and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals, and portions of such sensitive information may be required to be encrypted by the Utility.
If any of these events were to transpire, it could subject PG&E Corporation and the Utility to financial liability. PG&E Corporation and the Utility are subject to federal and state privacy laws, which grant consumers rights and protections, including, among other things, the ability to opt out of receiving certain communications and certain data sharing with third parties.
If any of these events were to transpire, it could subject PG&E Corporation and the Utility to financial liability. PG&E Corporation and the Utility are subject to federal and state privacy laws, which grant consumers rights and protections, including, among other things, the ability to opt out of receiving certain communications and data sharing with third parties.
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; 39 • 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; • 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.
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.
The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes.
The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for income tax purposes.
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, 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.
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.
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. 48 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 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.
Any assets acquired by a third party through eminent domain would be excluded from the Utility’s rate base, reducing the Utility’s revenues and opportunity to earn a return on such assets. In addition, third parties may attempt to bypass the Utility’s existing electric infrastructure system to provide retail electric service to discrete geographic areas or specific customers.
Any assets acquired by a third party through eminent domain would be excluded from the Utility’s rate base, reducing the Utility’s revenues and opportunity to earn a return on such assets. In addition, third parties attempt to bypass the Utility’s existing electric infrastructure system to provide retail electric service to discrete geographic areas or specific customers.
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. 38 The Utility may not effectively implement its wildfire mitigation initiatives.
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.
The amount of such fines, penalties, or customer refunds depends on a variety of factors and 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 also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires.
The amount of such fines, penalties, or customer refunds depends on a variety of factors and could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 47 The Utility also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires.
Further, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock.
Further, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation capital stock.
For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund.
For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 38 Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund.
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 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.
Additionally, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and to meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation.
The Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to meet its obligations to employees and creditors, and to pay preferred stock dividends, before it can distribute cash to PG&E Corporation.
Additionally, PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions.
PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions.
Approximately 25,000 circuit miles of the Utility’s nearly 80,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs.
Approximately 25,000 circuit miles of the Utility’s nearly 80,000 distribution overhead circuit miles and approximately 5,000 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs.
Failure to comply with SB 100 could result in fines imposed on PG&E Corporation and the Utility that could be material. The Utility develops its capital plans based on forecasts, including those around load growth, gas system planning, and transportation electrification, which assume that California continues to pursue consistent environmental policies.
Failure to comply with SB 100 could result in material fines being imposed on PG&E Corporation and the Utility. The Utility develops its capital plans based on forecasts, including those around load growth, gas system planning, and transportation electrification, which assume that California continues to pursue consistent environmental policies.
Such payment may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation common stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation’s ability to use its net operating loss carryforwards and other tax attributes.
Such payment may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation capital stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation’s ability to use its net operating loss carryforwards and other tax attributes.
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. 44 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. 45 The Utility’s operations are subject to extensive environmental laws, and such laws could change.
The rates paid by the Utility’s customers are impacted by the Utility’s costs, commodity prices, and broader energy trends. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customers’ rates.
The rates paid by the Utility’s customers are impacted by the Utility’s costs, commodity prices, and broader energy trends. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customers’ rates.
Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities.
Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the combined value of outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the combined value of the Equity Securities to increase their proportionate interest in the Equity Securities.
Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire.
Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire.
PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires.
PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires.
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.
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.
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 these substantial costs.
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.
Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 43 Risks Related to Environmental Factors Severe weather events, extended drought, and climate change could materially affect PG&E Corporation and the Utility.
Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 44 Risks Related to Environmental Factors Severe weather events, extended drought, and climate change could materially affect PG&E Corporation and the Utility.
PG&E Corporation and the Utility have been the subject of investigations, regulatory enforcement actions, or criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires.
PG&E Corporation and the Utility have been the subject of investigations, regulatory enforcement actions, and criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires.
The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions.
As a result, the Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions.
The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health, and financial risks, such as risks relating to operation of the Diablo Canyon nuclear generation units as well as the storage, handling, and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act.
The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health, and financial risks, such as risks relating to operation of the DCPP nuclear generation units as well as the storage, handling, and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act.
PG&E Corporation is a holding company and relies on dividends, distributions and other payments, advances, and transfers of funds from the Utility to meet its obligations. PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility.
PG&E Corporation is a holding company and relies on dividends, distributions, and other payments, advances, and transfers of funds from the Utility to pay dividends on its capital stock and meet its obligations. PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility.
Additionally, the Utility could experience workforce disruptions from personnel in those positions as a result of labor activity, the COVID-19 pandemic or other pandemics, or governmental regulation of pandemic protections. If the Utility were to experience such a shortage or disruptions, work stoppages could occur.
Additionally, the Utility could experience workforce disruptions from personnel in those positions as a result of labor activity, pandemics, or governmental regulation of pandemic protections. If the Utility were to experience such a shortage or disruptions, work stoppages could occur.
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 a reformed prudent manager standard.
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.
See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1. 47 Jurisdictions may attempt to acquire the Utility’s assets through eminent domain, and third parties may attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system. Jurisdictions may attempt to acquire the Utility’s assets through eminent domain (“municipalization”).
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”).
Once an ignition has occurred, the Utility is unable to control the extent of damages. The extent of damages for a wildfire is 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 primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
The electric power and natural gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could lead to the reduction in demand for natural gas as an energy resource that could impact the Utility’s ability to recover through rates its investment.
The electric power and natural gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could lead to the reduction in demand for natural gas as an energy resource that could impact the Utility’s ability to recover the value of its investments through rates.
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 2023 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 2024 Form 10-K.
If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties, the amount of which could be substantial, and, in the event of a judgment against the Utility, suffer further ongoing negative consequences.
If these investigations result in enforcement action against the Utility, the Utility could incur additional fines, penalties, customer rebates, or other payments, the amount of which could be substantial, and, in the event of a judgment against the Utility, suffer further ongoing negative consequences.
In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which 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 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.
Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results.
Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below.
The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs.
The CPUC or the FERC have not allowed and may in the future not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs.
The inability to recover all or a significant portion of costs in excess of insurance through rates or by collecting such rates in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The inability to recover all or a significant portion of costs in excess of insurance through rates could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Risks related to financial conditions, including risks related to: • PG&E Corporation’s and the Utility’s substantial indebtedness; • Restrictions in indebtedness documents; • Potential additional dilution to holders of PG&E Corporation common stock; • Ownership and transfer restrictions associated with PG&E Corporation common stock; • The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; • PG&E Corporation’s reliance on dividends, distributions and other payments from the Utility; • Restrictions on shareholders’ ability to change the direction or management of PG&E Corporation; 36 • Increased customer rates; • T h e Utility ’ s ability to manage its costs effectively; and • Inflation and supply chain issues .
Risks related to financial conditions, including risks related to: • PG&E Corporation’s and the Utility’s substantial indebtedness; • Restrictions in indebtedness documents; • Potential additional dilution to holders of PG&E Corporation common stock; • Ownership and transfer restrictions associated with PG&E Corporation capital stock; • The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; • PG&E Corporation’s reliance on dividends, distributions, and other payments from the Utility; • The Utility’s ability to manage its costs effectively; • Increased customer rates; and • Inflation and supply chain issues.
In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the safety certification required by AB 1054.
In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the annual safety certification.
If the Utility is unable to maintain an AB 1054 safety certification or if the Wildfire Fund is exhausted, the inability to access 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 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.
As of December 31, 2023, 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 $32.9 billion and $32.6 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, 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.
In particular, 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 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 intent to acquire such assets.
For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 37 Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees.
Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees.
These risks are discussed more fully below. 35 Risks related to wildfires, including risks related to: • The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires; • The 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires; • Recovery of excess costs in connection with wildfires; and • Implementation of wildfire mitigation initiatives.
Risks related to wildfires, including risks related to: • The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires; • The 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires; • Recovery of excess costs in connection with wildfires; and • Implementation of wildfire mitigation initiatives.
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.
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.
Reducing natural gas use reduces the gas customer base and could diminish the need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful,” potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which results in a reduction in associated rate recovery).
Reducing natural gas use reduces the gas customer base and could diminish the need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful” (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which may result in a reduction in associated rate recovery).
Further, the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, and the Utility may have less control over contractors than its employees.
Further, the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities. The Utility has less control over contractors than its employees but may retain liability for the quality and completion of the contractor’s work.
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 other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to meet its obligations.
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.
Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to: • The Enhanced Oversight and Enforcement Process; • Legislative and regulatory developments; • Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; • Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its cost s; and • Municipalization .
Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to: • The Enhanced Oversight and Enforcement Process; • Legislative and regulatory developments; • Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; • Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its costs; and • Attempts to acquire the Utility's assets and customers through municipalization or bypass.
To the extent the Utility’s criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions.
To the extent the Utility’s criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions. 40 Risks Related to Operations and Information Technology The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks.
The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in the agreements of those subsidiaries.
The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and is restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in financing agreements. See “Liquidity and Financial Resources” in Item 7. MD&A.
In addition, the OEIS has authority to approve and oversee compliance with the WMP and may determine that the Utility has failed to substantially comply with its WMP. 46 The 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; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC 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.
The 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.
PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.
For example, a default on indebtedness in a principal amount in excess of $200 million could result in a cross-default or cross-acceleration. 50 PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.
The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with matters that the CPUC’s SED may investigate.
The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with such regulations could result in penalties. The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations.
In addition, the Utility may be required under federal law to pay up to $275 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States. The Utility continues to face public concern about the safety of nuclear generation and nuclear fuel.
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.
See “Risks Related to Wildfires” above. The Utility is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.
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.
If the federal government withdraws its support for grid modernization or prohibits California from pursuing its environmental policies, or if California changes its policies, PG&E Corporation and the Utility may be unable to meet their environmental and financial goals. The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with such regulations could result in penalties.
If the federal government withdraws its support for grid modernization or prohibits California from pursuing its environmental policies, or if California changes its policies, PG&E Corporation and the Utility may be unable to meet their environmental and financial goals.
Risks related to operations and information technology, including risks related to: • The hazardous nature of the Utility’s electricity and natural gas operations; • Changes in the electric power and nat ural gas industries; • A cyber incident, cybersecurity breach , or physical attack; • The operation and decommissioning of the Utility’s nuclear generation facilities; and • Attracting and retaining specialty personnel.
Risks related to operations and information technology, including risks related to: • The hazardous nature of the Utility’s electricity and natural gas operations; • Changes in the electric power and natural gas industries; • A cyber incident, cybersecurity breach, or physical attack; • The operation and decommissioning of the Utility’s nuclear generation facilities; and • Attracting and retaining specialty personnel. 37 Risks related to environmental factors, including risks related to: • Severe weather events, extended drought , and climate change and events resulting from these conditions (including wildfires); and • Extensive environmental laws.
Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline. 49 Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in “Wildfire-Related Securities Claims — Claims in the Bankruptcy Court Process” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8).
Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in “Wildfire-Related Securities Claims — Claims in the Bankruptcy Court Process” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8).
Accordingly, PG&E Corporation’s cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility.
Accordingly, PG&E Corporation’s cash flow, ability to pay dividends on its capital stock, and ability to meet its debt service obligations under its existing and future indebtedness largely depend upon the earnings and cash flows of the Utility and the distribution of these earnings and cash flows to PG&E Corporation.
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 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.
PG&E Corporation and the Utility could be liable as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires.
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.
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. 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.
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.
In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives.
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 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.
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. 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. Inflation and supply chain issues may adversely affect PG&E Corporation and the Utility.
The Utility’s costs to decommission its nuclear facilities through nuclear decommissioning are subject to reasonableness review by the CPUC. The Utility will be responsible for any costs that the CPUC determines were not reasonably incurred, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility will be responsible for any costs that the CPUC determines were not reasonably incurred, which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The Utility may be unable to attract and retain specialty personnel and may face workforce disruptions.
As of December 31, 2023, PG&E Corporation had approximately $4.65 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, $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and $500 million of borrowings under the secured term loan agreement entered into in June 2020), and the Utility had approximately $48.0 billion of outstanding indebtedness.
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.
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.
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.
For more information about the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
The Utility maintains cyber liability insurance that covers certain losses and damages caused by cyber incidents, but adequate insurance may not continue to be available at rates the Utility believes are reasonable, or the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable through rates.
The Utility maintains cyber liability insurance that covers certain losses and damages caused by cyber incidents, but adequate insurance may not continue to be available at rates the Utility believes are reasonable, or the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable through rates. 43 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.
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.
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.
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.
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.
Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Even if an action in opposition ultimately fails, regulatory proceedings may take longer to conclude and be more costly to complete.
Nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power.
In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner.
In particular, the CPUC requires PG&E Corporation’s and the Utility’s Boards of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC also regulates the Utility’s capital structure.
In general, an ownership change occurs if the aggregate 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). 50 As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.
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).
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. The Utility generally recovers its electricity and natural gas procurement costs through rates as “pass-through” costs. Increases in the Utility’s commodity costs directly impact customer bills.
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.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeThe Executive Vice President and Chief Information Officer of PG&E Corporation and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions.
Biggest changeThe Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions.
PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk, such as: • Developing organizational understanding in managing cybersecurity risks to systems, assets, and data by regularly assessing cybersecurity internal controls and program maturity, including engaging independent third parties and participating in external regulatory compliance assessments; • Assessing, monitoring, and imposing contractual requirements on third-party service providers for cybersecurity risks and for compliance with PG&E Corporation’s and the Utility’s policies regarding access to company networks, information security, and technology; • Configuring and monitoring the system; employing policies, controls, and security tools, including training for employees and contractors; and limiting access and operating firewall rules as necessary and appropriate; • Utilizing multiple government and private assessors, consultants, auditors or other third parties, as well as an internal team, for intelligence gathering, security monitoring, threat hunting, and forensic activities; • Monitoring emerging data protection laws and regulations and implementing changes to processes designed to comply with any such laws and regulations; 53 • Responding to cybersecurity incidents as they are detected by containing consequences, investigating causes and impacts, and implementing mitigations; • Maintaining and utilizing plans for resilience, mitigation, and restoring any capabilities or services that were impaired due to a cybersecurity incident; • Maintaining cybersecurity liability insurance; • Maintaining physical controls on a risk-informed basis, including controlling access or monitoring as appropriate; and • Continuously improving the cybersecurity program by incorporating learning from past experiences and testing, reviewing, and enhancing the controls and capabilities discussed above, including conducting regular cybersecurity incident-response exercises.
PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk, such as: • Developing organizational understanding in managing cybersecurity risks to systems, assets, and data by regularly assessing cybersecurity internal controls and program maturity, including engaging independent third parties and participating in external regulatory compliance assessments; • Assessing, monitoring, and imposing contractual requirements on third-party service providers for cybersecurity risks and for compliance with PG&E Corporation’s and the Utility’s policies regarding access to company networks, information security, and technology; • Configuring and monitoring the system; employing policies, controls, and security tools, including training for employees and contractors; and limiting access and operating firewall rules as necessary and appropriate; • Utilizing multiple government and private assessors, consultants, auditors or other third parties, as well as an internal team, for intelligence gathering, security monitoring, threat hunting, and forensic activities; • Monitoring emerging data protection laws and regulations and implementing changes to processes designed to comply with any such laws and regulations; • Responding to cybersecurity incidents as they are detected by containing consequences, investigating causes and impacts, and implementing mitigations; • Maintaining and utilizing plans for resilience, mitigation, and restoring any capabilities or services that were impaired due to a cybersecurity incident; • Maintaining cybersecurity liability insurance; • Maintaining physical controls on a risk-informed basis, including controlling access or monitoring as appropriate; and • Continuously improving the cybersecurity program by incorporating learning from past experiences and testing, reviewing, and enhancing the controls and capabilities discussed above, including conducting regular cybersecurity incident-response exercises.
They are responsible for assessing and managing cybersecurity risks in collaboration with the enterprise risk management team. Such persons are informed about cybersecurity vulnerabilities and incidents through daily and weekly operating reviews conducted by management and personnel closest to the work as part of the Lean operating system and as otherwise appropriate. 54
They are responsible for assessing and managing cybersecurity risks in collaboration with the enterprise risk management team. Such persons are informed about cybersecurity vulnerabilities and incidents through daily and weekly operating reviews conducted by management and personnel closest to the work as part of the Lean operating system and as otherwise appropriate.
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. Risk Factors.
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.
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. 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.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeThe Utility will continue to lease the Property pursuant to the Lease, as amended, until closing in June 2025. For more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8. The Utility owns approximately 135,000 acres of land, including approximately 100,000 acres of watershed lands.
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.
Business, under “Electric Utility Operations” and “Natural Gas Utility 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 9 million square feet of real property, including 7 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. In total, the Utility occupies approximately 7.5 million square feet of real property, including 5.5 million square feet owned by the Utility.
In 2002, the Utility agreed to implement its 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.
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.
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. The Utility’s goal is to implement all the LCC transactions by the first quarter of 2024, subject to securing all required regulatory approvals.
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.
Removed
On September 17, 2021, the sale of the SFGO closed and the Utility entered into a leaseback agreement with the new SFGO owner (the “Leaseback Agreement”) to lease back certain space within the SFGO to allow for additional time to relocate critical facilities to other Utility sites.
Added
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
The Leaseback Agreement commenced on September 17, 2021, and the lease term was extended through June 30, 2024. On October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters.
Removed
The term of the lease began on April 8, 2022, and the lease grants the Utility an option to purchase the legal parcel that contains the Lakeside Building.
Removed
On July 11, 2023, the Utility and the Landlord (as defined in Note 2 of the Notes to the Consolidated Financial Statements in Item 8.) entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Property, as modified.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL 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. Risk Factors and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 .
Biggest changeITEM 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.
Added
Risk Factors and Notes 9, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8 .
Added
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.
Added
The Utility continues to work with the California Coastal Commission and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues. 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.
Added
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.
Added
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.
Added
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. 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.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

15 edited+3 added−1 removed0 unchanged
Biggest changePeterman 45 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 Ajay Waghray 62 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 changePeterman 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.
Santos 63 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.
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.
Poppe 55 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 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.
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 21, 2024. 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, 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.
May 2016 to December 2018 Sumeet Singh 45 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.
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.
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 John R.
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.
Santos 63 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 March 15, 2021 to October 15, 2023 President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc.
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.
Burke 56 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 55 Carla J.
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.
May 2016 to December 2018 Jason M. Glickman 43 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 Stephanie N.
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.
March 2015 to December 2018 Ajay Waghray 62 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.
September 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.
Glickman 43 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 Kaled Awada 49 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.
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.
February 2020 to August 2020 58 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 Kaled Awada 49 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.
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.
Williams 41 Vice President, Chief Financial Officer and Controller, Pacific Gas and Electric Company 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 Sumeet Singh 45 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.
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.
September 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 57 The following individuals serve as executive officers of the Utility as of February 21, 2024. Except as otherwise noted, all positions have been held at the Utility. Marlene M.
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.
September 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 59 PART II
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
Simon 59 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 56 Marlene M.
Added
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.
Added
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.
Added
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 changeMD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 of the Notes to the Consolidated Financial Statements in Item 8. Share Exchanges On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement.
Biggest changeMD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 of the Notes to the Consolidated Financial Statements in Item 8.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES As of February 14, 2023, there were 42,199 holders of record of PG&E Corporation common stock.
ITEM 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.
Removed
On the dates and in the amounts set forth in the table below, the Fire Victim Trust exchanged a total of 477,743,590 Plan Shares, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares.
Removed
As of February 14, 2024, the Fire Victim Trust reported having sold all of the shares of PG&E Corporation common stock it had owned and no longer owning any shares.
Removed
Date Shares Exchanged January 1 - December 31, 2022 230,000,000 January 9, 2023 60,000,000 April 11, 2023 60,000,000 July 12, 2023 60,000,000 December 13, 2023 67,743,590 Total Shares Exchanged 477,743,590 Each exchange was effected in reliance on the exemption from registration under Section 3(a)(10) of the Securities Act. See “Tax Matters” in Item 7.
Removed
MD&A below and “Share Exchange and Tax Matters Agreement” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K for a detailed discussion of the exchange and the terms of the Share Exchange and Tax Matters Agreement, respectively.

Item 7. Management's Discussion & Analysis

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

180 edited+80 added−132 removed90 unchanged
Biggest changePartially offset by: • a decrease of approximately $350 million in insurance costs related to the Utility’s adoption of self-insurance; • the recognition of approximately $310 million of previously deferred expenses, which were authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in 2022; • the recognition of $85 million in expenses related to the Kincade SED Settlement (as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in 2022; • the recognition of $77 million in charges as a result of its voluntary separation program in 2022; • the recognition of $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in 2022; • a decrease of approximately $70 million in pass-through costs related to public purpose programs in 2023.
Biggest change(See Note 3 of the Notes to the Consolidated Financial Statements in Item 8); • a decrease of approximately $160 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) in 2023; and • a decrease of approximately $50 million in pass-through costs related to public purpose programs in 2024.
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 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. 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 recorded these costs to the memorandum and balancing accounts as set forth in the following table: Recorded Costs (in millions) WMPMA $ 2,095 FRMMA 165 Gas storage balancing account 101 In line inspection memorandum account 92 Other 45 Total $ 2,498 In connection with the WGSC application, the Utility also requested interim rate relief of $583 million.
The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table: (in millions) Recorded Costs WMPMA $ 2,095 FRMMA 165 Gas storage balancing account 101 In line inspection memorandum account 92 Other 45 Total $ 2,498 In connection with the WGSC application, the Utility also requested interim rate relief of $583 million.
The proposed amount reflects an approximately 11% decrease over the current rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above).
The proposed amount reflects an approximately 11% decrease over the rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above).
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 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.
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 made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. The Utility has requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO.
The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. The Utility requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO.
Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.
Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred.
Actual results may differ materially from these estimates and assumptions. See Note 14 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 87 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.
Actual results may differ materially from these estimates and assumptions. See Note 14 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 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.
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, 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, and regulatory recovery.
For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred.
For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred.
The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020. The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures.
The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020. 76 The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures.
In general, an ownership change occurs if the aggregate 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 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).
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. • 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 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.
Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation common stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.
Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.
The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following applications.
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.
These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs.
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.
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.
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.
The CPUC may also authorize balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs.
The CPUC may also authorize balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims.
Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.
Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 20 years is being used to amortize the Wildfire Fund asset.
Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies.
Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies.
The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 74 REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies.
The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the NRC, and other federal and state regulatory agencies.
The Utility’s undiscounted future costs could increase to as much as $2.4 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 $2.3 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.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse.
Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter.
Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, communications with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter.
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 plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system.
The Utility has set a long-term goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system.
On June 8, 2023, the CPUC adopted a final decision granting the Utility’s interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision.
On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision.
During this period, the laws governing the remediation process may change, as well as site conditions, which could affect the cost of the remediation effort. As of December 31, 2023 and 2022, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each.
During this period, the laws governing the remediation process may change, as well as site conditions, which could affect the cost of the remediation effort. As of December 31, 2024 and 2023, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each.
Once an ignition has occurred, the Utility is unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire. The financial impact of past wildfires is significant.
Once an ignition has occurred, the Utility may be unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire. The financial impact of past wildfires is significant.
In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2023, 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, 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.
Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust 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.
Risk Factors, Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Item 8, and “Regulatory Matters” below. • PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings.
See Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Item 8, and “Regulatory Matters” below. • PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings.
The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with Diablo Canyon. On June 5, 2023, the California State Lands Commission approved an extension of the Utility’s lease at Diablo Canyon through October 31, 2030.
The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with DCPP. On June 5, 2023, the California State Lands Commission approved an extension of the Utility’s lease at DCPP through October 31, 2030.
The approval is subject to the following conditions: (1) the NRC continues to authorize Diablo Canyon operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that Diablo Canyon extended operations are imprudent or unreasonable.
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.
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.
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).
Investing Activities The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2023, compared to December 31, 2022.
Investing Activities The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2024, compared to December 31, 2023.
Update on Ownership Restrictions in PG&E Corporation’s Amended Articles 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.
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.
At December 31, 2023 and 2022, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $57 million and $54 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
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.
Significant changes in any of these estimates could materially impact the amortization period. PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required by additional information, and the expected life of the Wildfire Fund will be adjusted as required.
Significant changes in any of these estimates could materially impact the amortization period. PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and when additional information becomes available, and the expected life of the Wildfire Fund will be adjusted as required.
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, 2023 $ 926 3 $ 457 December 31, 2022 $ 814 1 $ 162 (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, 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.
Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $2.4 billion was accounted for as long term as of December 31, 2024. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts.
The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to its individual contribution amount.
For the Utility’s defined benefit pension plan, the assumed return of 6.0% compares to a ten-year actual return of 5.3%. 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, 2023.
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.
The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire and $100 million related to the 2019 Kincade fire in 2023. These charges were partially offset by $425 million of probable recoveries through the Wildfire Fund, insurance, and the WEMA related to the 2021 Dixie fire.
The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund and WEMA and $100 million related to the 2019 Kincade fire in 2023.
During the years ended December 31, 2023 and 2022, the Utility recorded amortization and accretion expense of $567 million and $477 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, 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.
The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS and the CPUC approve guidelines (see “SB 884 10-Year Distribution Undergrounding Program” below). Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply.
The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS approves guidelines. See “SB 884 10-Year Distribution Undergrounding Program” below. Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed.
On December 14, 2023, the CPUC approved extended operations at Diablo Canyon until October 31, 2029 for Unit 1 and October 31, 2030 for Unit 2.
On December 14, 2023, the CPUC approved extended operations at DCPP until October 31, 2029 for Unit 1 and October 31, 2030 for Unit 2.
Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA.
Because rate recovery may require CPUC authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2024, the Utility had recorded an aggregate amount of approximately $3.6 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA.
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. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage.
The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the AFSI of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S.
The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base. 72 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, including funds available from self-insurance (see “2023 General Rate Case” in the “Regulatory Matters” section below for more information), the 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 2020-2022 and 2023-2025 WMPs and the costs previously incurred in connection with the 2019 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 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.
The 364-day tranche loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375%, or (2) the alternate base rate plus an applicable margin of 0.375%.
The loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.
(1) The revenue requirement request amounts do not include interest. Wildfire Mitigation and Catastrophic Events Cost Recovery Applications 2021 WMCE Application On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”).
Wildfire Mitigation and Catastrophic Events Cost Recovery Applications 2021 WMCE Application On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”).
The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table: Proceeding Request (1) Status 2020 WMCE Revenue requirement of approximately $1.28 billion Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023. 2021 WMCE Revenue requirement of approximately $1.47 billion Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. 2022 WMCE Revenue requirement of approximately $1.29 billion Filed December 2022.
The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2024 are summarized in the following table: Proceeding Request (1) Status 2021 WMCE Revenue requirement of approximately $1.47 billion Partial settlement agreement to recover $721 million of revenue requirement approved August 2023.
PG&E Corporation and the Utility recorded $102 million and $6 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2023 and 2022, respectively.
PG&E Corporation and the Utility recorded $72 million and $102 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2024 and 2023, respectively.
As of December 31, 2023, the Utility has recorded receivables for regulatory recovery of $561 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire.
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.
Credit Facilities and Term Loans As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability.
Facilities and Term Loans As of December 31, 2024, PG&E Corporation and the Utility had $500 million and $3.8 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the $1.5 billion Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability.
As of December 31, 2023, PG&E Corporation and the Utility recorded $325 million and $275 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.
As of December 31, 2024, PG&E Corporation and the Utility recorded $600 million and $156 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.
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. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $4 million and $3 million at December 31, 2023 and 2022, 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 $5 million and $4 million at December 31, 2024 and 2023, respectively.
As of December 31, 2023, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.125 billion, $400 million, $1.6 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries.
As of December 31, 2024, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.225 billion, $1.925 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries.
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 2024 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 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 2025 was 7.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2033 and beyond.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur $10.4 billion of capital expenditures in 2024.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur $12.9 billion of capital expenditures in 2025.
The Utility expects to submit its undergrounding plan to the OEIS in mid-2024 before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5. LEGISLATIVE AND REGULATORY INITIATIVES Inflation Reduction Act In 2022, the Inflation Reduction Act became law.
The Utility expects to submit its undergrounding plan to the OEIS after final guidelines are issued before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5. 81 LEGISLATIVE AND REGULATORY INITIATIVES Inflation Reduction Act In 2022, the Inflation Reduction Act became law.
Description of the Business regarding how the Utility’s revenues are determined. 60 Key Factors Affecting Financial Results PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors: • The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery.
Key Factors Affecting Financial Results PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors: • The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery.
PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements 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 in Item 8. 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, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $750 million in Other noncurrent liabilities, $450 million in Current assets - Wildfire Fund asset, and $4.3 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets.
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.
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.
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.
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. As of December 31, 2023, the Utility has recorded a Wildfire Fund receivable of $600 million for the 2021 Dixie 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.
These costs are passed through to customers and do not impact net income.
These costs are passed through to customers and do not impact net income (see “Operating Revenues” above).
These increases were due to the recognition of $1.3 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023, compared to charges of $608 million in 2022.
These decreases were due to the recognition of $1.27 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023, with no comparable activity in 2024.
For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below. 66 Wildfire-Related Claims, Net of Recoveries Costs related to wildfires decreased by $173 million, or 73%, in 2023 compared to 2022.
For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below. Wildfire-Related Claims, Net of Recoveries Costs related to wildfires increased by $30 million, or 47%, in 2024 compared to 2023.
The ALJ has adopted a schedule that would result in a final decision on the wildfire mitigation costs by November 2024 and a final decision on the gas safety and electric modernization costs by June 2025. 77 Forward-Looking Rate Cases The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC.
The administrative law judge has adopted a schedule that would result in a proposed decision on the wildfire mitigation costs in the first half of 2025 and a final decision on the gas safety and electric modernization costs by June 2025. Forward-Looking Rate Cases The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC.
Contributions to the Wildfire Fund The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.
Contributions to the Wildfire Fund The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period.
The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. At December 31, 2023, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.5 billion.
The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. At December 31, 2024, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.4 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.
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.
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.
On August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023.
On August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023. The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA.
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.
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.
On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but rejecting the 0.5% ROE adder for participation in the CAISO.
On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but denying the 0.5% ROE adder for participation in the CAISO, which results in a forecast transmission revenue requirement of $2.78 billion.
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.
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.
See Note 2 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Depreciation, Amortization, and Decommissioning The Utility’s depreciation, amortization, and decommissioning expenses decreased by $118 million, or 3%, in 2023 compared to 2022.
See Note 2 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 66 Depreciation, Amortization, and Decommissioning The Utility’s Depreciation, amortization, and decommissioning expenses increased by $451 million, or 12%, in 2024 compared to 2023.
The CPUC has granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025.
The CPUC has granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025. The Utility is on track to comply with its authorized regulatory capital structure when the waiver terminates.
The Utility is on track to comply with its authorized regulatory capital structure when the waiver terminates. 68 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.
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.

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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. 91
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

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