PG&E Corporation

Company Overview

Business Model: PG&E Corporation is a holding company whose primary operating subsidiary, Pacific Gas and Electric Company (the "Utility"), is a public utility operating in Northern and Central California. The Utility generates revenues primarily through the sale and delivery of electricity and natural gas to customers. It operates under a "cost-of-service" ratemaking model, where rates are set to allow recovery of service costs and a reasonable return on invested capital. The Utility's net income is decoupled from sales volume, depending instead on its ability to manage operating and capital costs within authorized revenue requirements.

Market Position: The Utility provides bundled natural gas service to over 97% of core customers, representing approximately 85% of the annual core market demand. In the electricity sector, it faces competition from Community Choice Aggregators (CCAs), Direct Access (DA) providers, and self-generation resources like rooftop solar. The Utility's service area, encompassing densely forested regions, presents unique wildfire risk management challenges. The company anticipates electric load growth driven by data centers, electric vehicle adoption, and building electrification, while expecting a decrease in natural gas demand due to California's climate policies.

Recent Strategic Developments: PG&E Corporation and the Utility are committed to a "triple bottom line" purpose focusing on people, planet, and prosperity, underpinned by a Lean operating model for effective decision-making and improved customer outcomes. Key strategic initiatives include:

• Climate Strategy: The 2022 Climate Strategy Report outlines goals to decarbonize the energy system, accommodate electrification, integrate distributed energy resources, and increase renewable energy utilization.
• Infrastructure Investment: The Utility plans to submit a 10-year Electric Undergrounding Plan to the Office of Energy Infrastructure Safety (OEIS) and has identified opportunities for investments in transmission for data centers, transportation electrification capacity, hydroelectric facilities, energy storage, information technology, and automation.
• Wildfire Mitigation: The OEIS approved the Utility’s 2026–2028 Wildfire Mitigation Plan (WMP) in February 2026. Senate Bill (SB) 254, effective September 19, 2025, established a Continuation Account to provide additional liquidity for catastrophic wildfire claims and prohibits the Utility from including the first $2.9 billion of fire risk mitigation capital expenditures (approved by the California Public Utilities Commission (CPUC) on or after January 1, 2026) in its equity rate base.
• Regulatory Outcomes: In December 2025, the CPUC approved a Return on Equity (ROE) of 9.98% for the Utility, effective January 1, 2026. The Federal Energy Regulatory Commission (FERC) approved a settlement in August 2025 for the Utility’s Transmission Owner Rate Case for 2024, setting a base ROE of 10.38% for electric transmission assets.
• Asset Acquisition & Partnerships: In June 2025, the Utility purchased the Oakland General Office property for $906 million. In January 2025, the Utility entered an agreement with Citizens Energy Corporation to lease entitlements to certain transmission assets, potentially involving up to $1.0 billion in investment from Citizens Energy Corporation.
• Diablo Canyon Power Plant (DCPP) Extension: SB 846 supports the extension of DCPP operations through no later than 2030, with costs attributable to all CPUC-jurisdictional load serving entities (LSEs). The Nuclear Regulatory Commission (NRC) deemed the license renewal application sufficient in December 2023, allowing continued operations pending review.

Geographic Footprint: The Utility operates in Northern and Central California. Its 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 sources natural gas from major basins in western North America, including western Canada, the Rocky Mountains, and the southwestern United States, as well as from fields in California.

Financial Performance

Revenue Analysis

Profitability Metrics:

• Gross Margin: 85.1%
• Operating Margin: 19.0%
• Net Margin: 10.8%

Investment in Growth:

• Capital Expenditures: $11,787 million (2025)
• Strategic Investments: The Utility forecasts capital expenditures of $12.4 billion for 2026, $13.4 billion for 2027, $15.4 billion for 2028, $16.3 billion for 2029, and $16.0 billion for 2030. These investments target transmission for data centers, system investments, transportation electrification capacity, hydroelectric facilities, energy storage, information technology, and automation.

Business Segment Analysis

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis, operating as one reportable segment. However, the filing provides detailed operational and revenue information for its core utility services: Electric Utility Operations and Natural Gas Utility Operations.

Electric Utility Operations

Financial Performance:

• Revenue: $18,318 million (+2.8% YoY)
• Key Growth Drivers: The Utility anticipates electric load growth from data center usage, electric vehicle adoption, and building electrification. Load growth is expected to reduce other customers' rates by spreading the revenue requirement over a larger usage base.

Product Portfolio:

• The Utility generates and delivers electricity to residential, commercial, industrial, and agricultural customers.
• Owned Generation Facilities (as of December 31, 2025):
  • Nuclear: Diablo Canyon (2 units, 2,240 MW)
  • Hydroelectric: Conventional (91 units, 2,628 MW), Helms pumped storage (3 units, 1,212 MW)
  • Fossil fuel-fired: Colusa Generating Station (1 unit, 657 MW), Gateway Generating Station (1 unit, 580 MW), Humboldt Bay Generating Station (10 units, 163 MW)
  • Battery Energy Storage: Elkhorn Battery Energy Storage System (1 unit, 183 MW)
  • Photovoltaic: 12 facilities (152 MW)
  • Total Net Operating Capacity: 7,815 MW from 121 units.
• Third-Party Generation: The Utility procures power and electric capacity, including renewable energy resources, through various agreements.
• Energy Storage: The Utility owned 183 MW and contracted for 3,024 MW of operational energy storage capacity as of December 31, 2025, meeting its CPUC-mandated 580 MW target by 2025. An additional 1,884 MW of battery energy storage is procured for future deployment.

Market Dynamics:

• The Utility faces competition from Community Choice Aggregators (CCAs), Direct Access (DA) providers, and customer-owned distributed generation (e.g., solar installations).
• The Net Energy Metering (NEM) and Net Billing Tariff (NBT) programs, which allow self-generating customers to receive bill credits, place upward rate pressure on non-NEM customers.

Sub-segment Breakdown:

• Customers (average for 2025): 5,656,450
• Deliveries (2025): 71,791 GWh
• Revenue by Customer Type (2025):
  • Residential: $6,976 million
  • Commercial: $7,022 million
  • Industrial: $1,929 million
  • Agricultural: $1,825 million
  • Public street and highway lighting: $105 million
• Average billed revenues per kWh (2025):
  • Residential: $0.2836
  • Commercial: $0.2527
  • Industrial: $0.1403
  • Agricultural: $0.3636

Natural Gas Utility Operations

Financial Performance:

• Revenue: $6,617 million (+0.1% YoY)
• Key Growth Drivers: Customer demand for natural gas is expected to decrease due to California's climate policies, potentially leading to stranded assets and increased decommissioning costs if investments are not recovered through rates.

Product Portfolio:

• The Utility provides natural gas transportation services to "core" (small commercial and residential) and "non-core" (industrial, large commercial, natural gas-fired electric generation) customers.
• Natural Gas System Assets (as of December 31, 2025):
  • Distribution pipelines: Approximately 45,400 miles
  • Transmission pipelines: Approximately 5,500 miles (backbone and local)
  • Compressor stations: 7 on backbone, 1 on local transmission system
  • Underground storage fields: 3 owned, 25% interest in a fourth
• Natural Gas Supplies: The Utility purchases natural gas from western North America (Canada, Rocky Mountains, southwestern U.S.) and California fields. In 2025, approximately 304,000 MMcf of natural gas was purchased, with substantially all under contracts of one year or less.

Market Dynamics:

• The Utility competes with other natural gas pipeline companies for transportation services into the southern California market and with third-party storage providers in Northern California.
• Local jurisdictions in California have enacted prohibitions or restrictions on natural gas use, contributing to declining demand.

Sub-segment Breakdown:

• Customers (average for 2025): 4,633,685
• Bundled gas sales (2025): 204,813 MMcf
• Revenue by Customer Type (2025):
  • Residential (bundled): $3,651 million
  • Commercial (bundled): $1,074 million
  • Transportation service only: $1,937 million
• Average billed bundled gas sales revenues per Mcf (2025):
  • Residential: $24.39
  • Commercial: $17.59

Capital Allocation Strategy

Shareholder Returns:

• Share Repurchases: Not explicitly disclosed.
• Dividend Payments:
  • PG&E Corporation Common Stock: $220 million (2025)
  • PG&E Corporation Mandatory Convertible Preferred Stock: $97 million (2025)
  • Pacific Gas and Electric Company Common Stock: $2,350 million (2025)
  • Pacific Gas and Electric Company Preferred Stock: $14 million (2025)
• Future Capital Return Commitments: PG&E Corporation targets consistent dividend increases, aiming for a dividend payout ratio of approximately 20% of core earnings by 2028. The Board of Directors retains authority to change this target.

Balance Sheet Position (PG&E Corporation Consolidated):

• Cash and Equivalents: $713 million (as of December 31, 2025)
• Total Debt: $58,208 million (as of December 31, 2025)
• Net Cash Position: $(57,495) million (as of December 31, 2025)
• Credit Rating: All three credit rating agencies have increased PG&E Corporation’s and the Utility’s issuer credit ratings since 2020. However, the Utility’s unsecured credit rating remains below investment grade with one major agency, potentially requiring increased collateral postings.
• Debt Maturity Profile (PG&E Corporation Consolidated, principal repayment amounts at December 31, 2025):
  • 2026: $821 million
  • 2027: $7,130 million
  • 2028: $4,015 million
  • 2029: $2,350 million
  • 2030: $4,360 million
  • Thereafter: $39,070 million

Cash Flow Generation (PG&E Corporation Consolidated):

• Operating Cash Flow: $8,716 million (2025)
• Free Cash Flow: $(3,071) million (2025) (Calculated as Operating Cash Flow - Capital Expenditures)

Operational Excellence

Production & Service Model: PG&E Corporation and the Utility employ a Lean operating model to drive effective decision-making, reduce operational difficulties, and deliver better outcomes for customers and communities. The Utility's generation operations prioritize safety, compliance, environmental stewardship, and asset reliability, focusing on continuous improvement, risk-informed decision-making, and adherence to industry standards for asset risk management and lifecycle optimization.

Supply Chain Architecture:

• Key Suppliers & Partners: The Utility purchases natural gas directly from producers and marketers in Canada and the United States. It relies on international producers for nuclear fuel to diversify sources and ensure supply security. Third-party contractors are engaged for work such as facility patrolling, inspection, vegetation management, construction, and demolition.

Facility Network:

• Manufacturing: The Utility owns and operates a diverse portfolio of generation facilities, including nuclear, hydroelectric, fossil fuel-fired, battery energy storage, and photovoltaic plants across California.
• Distribution: The electric network includes approximately 18,000 circuit miles of transmission lines, 33 electric transmission substations, 109,000 circuit miles of distribution lines (27% underground, 73% overhead), 59 transmission and distribution substations, and 601 distribution substations. The natural gas system comprises approximately 45,400 miles of distribution pipelines, 5,500 miles of transmission pipelines, 8 compressor stations, and 3 wholly-owned underground natural gas storage fields (with a 25% interest in a fourth).

Operational Metrics:

• Safety: In 2025, the Utility reported four serious injuries or fatalities (SIF-A) incidents, resulting in one fatality and three serious injuries, and a SIF-P rate (potential for serious injury or fatality per 200,000 hours worked) of 0.051.
• Wildfire Prevention: The Utility's equipment was not involved in the ignition of any major wildfires in 2025, and CPUC-reportable ignitions decreased compared to 2024 due to operational improvements.
• Nuclear Operations: DCPP achieved an average capacity factor of 90% in 2025.
• Energy Storage: The Utility met its requirement to make 580 MW of qualifying storage capacity operational by 2025.
• Workforce: The Utility's turnover rate for 2025 was 3.8%. Approximately 46% of employees have over 10 years of tenure, with an average tenure of 11 years.

Market Access & Customer Relationships

Go-to-Market Strategy:

• Distribution Channels: The Utility provides electricity and natural gas services across Northern and Central California.
• Direct Sales: The Utility offers bundled natural gas service, serving over 97% of core customers.
• Channel Partners: The Utility provides transmission, distribution, metering, and billing services to customers of Direct Access (DA) providers and Community Choice Aggregators (CCAs), which procure their own electricity supplies.

Customer Portfolio:

• Customer Concentration: No single customer accounted for 10% or more of consolidated revenues for electricity or bundled gas sales in 2025, 2024, or 2023, indicating low customer concentration risk.

Geographic Revenue Distribution: The Utility's operations and revenue generation are concentrated in Northern and Central California.

Competitive Intelligence

Market Structure & Dynamics

Industry Characteristics: The electric power industry is undergoing significant transformation driven by technological advancements and decarbonization policies. This includes increasing deployment of distributed energy resources (e.g., solar, electric vehicles, battery storage) by customers and third parties, necessitating grid modernization. Electric load growth is expected from data centers, electric vehicle adoption, and building electrification. Conversely, natural gas demand is projected to decline due to climate goals, posing risks of stranded gas assets.

Competitive Positioning Matrix:

Direct Competitors

• Energy Service Providers (DA): Qualifying non-residential electric customers can purchase electricity from these providers.
• Community Choice Aggregators (CCAs): Cities, counties, and public agencies can procure electricity for local residents and businesses.
• Governmental Entities: Cities and irrigation districts may provide retail electric service, potentially bypassing or acquiring Utility infrastructure through eminent domain.
• Natural Gas Pipeline Companies: Competition for natural gas transportation into the southern California market.
• Third-Party Storage Providers: Competition for natural gas storage services in Northern California.

Emerging Competitive Threats: Increasing deployment of distributed energy resources and energy storage by customers and third parties, as well as potential changes in law allowing private companies to serve retail electricity without CPUC regulation.

Competitive Response Strategy: The Utility is collaborating with regulators and stakeholders on policies like cost allocation and rate design to ensure load growth improves customer affordability. It aims to achieve cost savings through increased efficiencies, including waste elimination via the Lean operating system, to manage upward pressure on customer rates from capital investments and environmental regulations.

Risk Assessment Framework

Strategic & Market Risks

• Market Dynamics: The Utility faces uncertainty in predicting the location and pace of electric load growth due to customer demand, policy environment, and macroeconomic factors. Declining natural gas demand, driven by climate policies, could lead to gas assets becoming "not used and useful," resulting in accelerated depreciation or impairment and significant decommissioning costs.
• Technology Disruption: The electric power and natural gas industries are undergoing transformative changes due to technological advancements and decarbonization efforts. The Utility may struggle to adapt effectively to these changes, potentially impacting its business model and strategy.

Operational & Execution Risks

• Supply Chain Vulnerabilities: Inflation, import tariffs, and labor shortages have led to increased prices for equipment, materials, and services, as well as longer lead times and delivery delays. These issues could delay planned maintenance and capital projects, impacting financial performance if costs cannot be offset.
• Geographic Concentration: PG&E Corporation and the Utility's business activities are concentrated in the electric and gas utility industry within Northern and Central California, making them susceptible to events and economic factors unique to this region.
• Capacity Constraints: Operations are inherently hazardous, with risks including equipment failure, natural gas overpressure events, prolonged electrical blackouts, and dam failures. These could disrupt service, damage assets, cause injuries or fatalities, and lead to significant claims and costs. The Utility's ability to efficiently construct, maintain, operate, protect, and decommission facilities is subject to risks beyond its control.

Financial & Regulatory Risks

• Market & Financial Risks: The Utility's financial results depend on sufficient authorized revenues from the CPUC and FERC and its ability to manage costs within these authorizations. Actual costs may exceed forecasts, and delays in cost recovery can increase financing costs. Substantial indebtedness ($58.2 billion as of December 31, 2025) limits operating flexibility, increases refinancing costs, and heightens vulnerability to adverse economic conditions and catastrophic events.
• Credit & Liquidity: Credit ratings affect the cost and availability of borrowings. Non-compliance with debt covenants could trigger defaults and accelerate repayment obligations.
• Regulatory & Compliance Risks: The Utility is subject to extensive federal, state, and local laws and regulations. Non-compliance can result in material fines, penalties, litigation, and reputational harm. The Enhanced Oversight and Enforcement Process (EOEP) could lead to the Utility losing its license to operate. The Inflation Reduction Act may result in federal cash tax liabilities starting in 2028 if repair and maintenance expenses are not deductible under the corporate alternative minimum tax.
• Data Privacy: The Utility collects sensitive customer, employee, and operational data. Cyber incidents, human error, or data misappropriation (potentially exacerbated by generative artificial intelligence) could lead to operational disruption, data loss, significant expenses, and regulatory penalties under laws like the California Consumer Privacy Act (CCPA).

Geopolitical & External Risks

• Geographic Dependencies: Concentration in Northern and Central California exposes the Utility to regional events, environmental conditions, and regulatory decisions without the benefit of geographic diversification.
• Trade Relations: Inflationary pressures, import tariffs, and trade wars can increase operating costs.
• Wildfire Risk: The Wildfire Fund and Continuation Account, established by AB 1054 and SB 254, may not fully mitigate liability for catastrophic wildfires. The Utility's liabilities for past fires (e.g., 2019 Kincade fire: $1.325 billion, 2021 Dixie fire: $2.15 billion, 2022 Mosquito fire: $350 million) could exceed estimates and available insurance. The Utility's ability to recover costs through rates depends on prudency determinations by regulators.
• Climate Change: Severe weather events, extended drought, and climate change intensify wildfire risks, increase stress on the energy supply network, reduce hydroelectric output, and cause physical damage to infrastructure. These impacts could lead to lower revenues, increased expenses, and regulatory penalties if the Utility cannot adapt effectively or recover costs.

Innovation & Technology Leadership

Research & Development Focus:

• Core Technology Areas: The Utility is integrating forward-looking climate data and tools into decision-making to build resilience against climate hazards. It leverages remote sensing technology for vegetation management and invests in pipeline replacements, strength testing, and real-time monitoring systems for gas safety.
• Innovation Pipeline: The Utility has identified future investment opportunities in transmission for data centers, transportation electrification capacity, hydroelectric facilities, energy storage, information technology, and automation to support the clean energy transition and grid modernization.

Intellectual Property Portfolio: Not explicitly disclosed.

Technology Partnerships: The Utility partners with innovators to reduce the cost of electric vehicle ownership.

Leadership & Governance

Executive Leadership Team

Leadership Continuity: The Utility's workforce is aging, with approximately 19% of employees eligible to retire, potentially leading to a shortage of experienced personnel in specialty operational positions.

Board Composition: PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, oversee cybersecurity risk management. The People and Compensation Committee reviews inclusion and belonging strategy and performance.

Human Capital Strategy

Workforce Composition:

• Total Employees: Approximately 29,000 regular employees at the Utility and 10 at PG&E Corporation as of December 31, 2025.
• Geographic Distribution: Primarily Northern and Central California.
• Skill Mix: Approximately 17,500 (60%) of the Utility's regular employees are covered by collective bargaining agreements with the International Brotherhood of Electrical Workers Local 1245, the Engineers and Scientists of California International Federation of Professional and Technical Engineers 20, and the Service Employees International Union Local 24/7.

Talent Management:

• Acquisition & Retention: Human capital objectives focus on building and retaining an engaged, well-trained, and equitably-paid workforce. The Utility's turnover rate for 2025 was 3.8%. Approximately 46% of employees have over 10 years of tenure, with an average of 11 years. The PowerPathway™ workforce development program aims to enlarge the talent pool for skilled craft and utility industry jobs.
• Employee Value Proposition: The company offers technical, leadership, and compliance training, as well as integrated health and wellness programs. Financial incentives include a Short-Term Incentive Plan (STIP) focused on safety, customer impact, and financial health.

Diversity & Development:

• Diversity Metrics: The Utility supports 12 Employee Resource Groups and three Engineering Network Groups to foster inclusion and belonging.
• Development Programs: Training, leadership development, and career advancement opportunities are provided through various programs, including PowerPathway™.
• Culture & Engagement: The company aims to foster an inclusive workplace culture, using employee surveys to measure and improve engagement.

Environmental & Social Impact

Environmental Commitments:

• Climate Strategy: PG&E Corporation and the Utility's 2022 Climate Strategy Report outlines plans to achieve California's climate goals: 40% GHG reduction by 2030 (vs. 1990), 60% renewable electricity sales by 2030, state carbon neutrality by 2045, and 100% renewable/zero-carbon electricity by 2045.
• Emissions Targets: Initiatives include reducing methane leaks from the natural gas system, sulfur hexafluoride emissions from the electric system, and electrifying vehicles, buildings, and facilities. The Utility achieved a third-party verified CO2 emissions rate of 16 pounds of CO2 per MWh for electricity delivered to retail customers in 2024.
• Renewable Energy: The company promotes energy efficiency programs, has contracts for over 4.9 GW of battery energy storage, supports over 820,000 electric vehicles, and has over 950,000 interconnected private solar customers. It is advancing decarbonization of the natural gas delivery system, meeting methane emission reduction targets ahead of schedule.

Supply Chain Sustainability: Not explicitly disclosed.

Social Impact Initiatives:

• Community Investment: The company is committed to its workforce, customers, and local communities, providing programs like the California Alternate Rates for Energy Program (CARE) for low-income customers.

Business Cyclicality & Seasonality

Demand Patterns:

• Seasonal Trends: Electric bills are generally higher in summer (May-October) due to increased air conditioning demand. Gas bills are typically higher in winter (November-March) due to heating demand.
• Economic Sensitivity: Electric load growth is influenced by data center usage, electric vehicle adoption, and building electrification, but its pace and location are subject to customer demand, policy, and macroeconomic factors. Natural gas demand is expected to decrease due to climate policies.

Planning & Forecasting: The Utility's ability to accurately predict load growth is limited, impacting planning and forecasting.

Regulatory Environment & Compliance

Regulatory Framework:

• Industry-Specific Regulations: The Utility is extensively regulated by the CPUC, FERC, NRC, OEIS, and other federal, state, and local agencies concerning rates, safety, environmental protection, and operations. Penalties for non-compliance can be substantial (up to $100,000 per day per violation by CPUC, up to $1 million per day by FERC).
• Legal Proceedings:
  • CZU Lightning Complex Fire Notices of Violation: Governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, alleging environmental, vegetation management, and unpermitted work violations. A probable, but immaterial, liability has been recorded.
  • Butte Canal Breach: Environmental violations were alleged in connection with a canal breach in August 2023. A probable liability has been incurred, but the amount is not reasonably estimable.
  • Wildfire-Related Securities Litigation: PG&E Corporation faces wildfire-related securities claims from the 2017 Northern California wildfires and 2018 Camp fire. A $300 million liability has been recorded for probable losses. A $100 million proposed settlement for consolidated securities actions was filed for preliminary approval in January 2026.

Tax Strategy & Considerations

Tax Profile:

• Effective Tax Rate: PG&E Corporation's effective tax rate was (12.1)% in 2025. The Utility's effective tax rate was (6.7)% in 2025.
• Geographic Tax Planning: PG&E Corporation files a consolidated U.S. federal income tax return and a combined state income tax return in California.
• Tax Reform Impact: The Inflation Reduction Act's 15% corporate alternative minimum tax may lead to federal cash tax liabilities for PG&E Corporation starting in 2028 if repairs and maintenance expenses are not deductible. California's new law suspending net operating loss use (2024-2026) means PG&E Corporation expects to pay state income taxes in 2026.

Net Operating Loss Carryforwards: As of December 31, 2025, PG&E Corporation had U.S. federal net operating loss carryforwards of approximately $38.3 billion and California net operating loss carryforwards of approximately $34.1 billion. PG&E Corporation does not expect to pay significant federal cash taxes until at least 2031. Ownership and transfer restrictions on PG&E Corporation common and preferred stock are in place to preserve the ability to utilize these tax attributes.

Insurance & Risk Transfer

Risk Management Framework: The Utility manages market risk through programs designed to support business objectives, reduce commodity cost volatility, and manage cash flows, using derivative instruments for non-trading (risk mitigation) purposes. Cybersecurity is identified as a key enterprise risk managed through an enterprise risk management system.

Insurance Coverage:

• Wildfire Liability: Since August 2023, the Utility's wildfire liability insurance up to $1.0 billion is entirely self-insured through at least 2026, with a 5% deductible (capped at $50 million).
• Nuclear Facilities: The Utility maintains insurance through Nuclear Electric Insurance Limited (NEIL) and European Mutual Association for Nuclear Insurance (EMANI) for property damage and business interruption at DCPP (up to $3.2 billion per nuclear incident, $2.5 billion per non-nuclear incident) and Humboldt Bay independent spent fuel storage installation (up to $50 million). Public liability claims from nuclear incidents are limited to approximately $16.3 billion under the Price-Anderson Act, with the Utility purchasing $500 million in public liability insurance and potentially being assessed up to $332 million per incident under a loss-sharing program.

Risk Transfer Mechanisms:

• Wildfire Fund and Continuation Account: Established by AB 1054 and SB 254, these statewide funds are available to reimburse eligible wildfire claims exceeding $1.0 billion (or required insurance coverage). The Wildfire Fund is capitalized with at least $21 billion, and the Continuation Account with up to $18 billion, through customer charges and utility contributions. Reimbursement from these funds is subject to CPUC prudency review and a disallowance cap (approximately $4.7 billion for the Utility in 2025).
• Regulatory Recovery: The Utility seeks recovery of wildfire-related costs through FERC Transmission Owner (TO) rates and the Wildfire Expense Memorandum Account (WEMA), subject to prudency standards and the presumption of reasonableness under AB 1054. As of December 31, 2025, probable recoveries for the 2021 Dixie fire and 2022 Mosquito fire totaled $2.303 billion and $424 million, respectively, from insurance, FERC TO rates, WEMA, and the Wildfire Fund.