2025 FOURTH QUARTER AND FULL YEAR EARNINGS February 12, 2026 Delivering For Customers AND Investors 1
2 This presentation and the oral remarks made in connection with it contain statements regarding PG&E Corporation’s and Pacific Gas and Electric Company’s (the “Utility”) future performance, including expectations, objectives, and forecasts about operating results (including 2026 non-GAAP core earnings), debt and equity issuances, refinancing activity, rate base growth, capital expenditures, cash flow, cost savings, customer bills, inflation, wildfire risk mitigation, wildfire-related cost recovery, dividends, load growth, operating and maintenance costs, financing efficiency, capital to expense ratio, technology (including AI) and regulatory developments. These statements and other statements that are not purely historical constitute forward-looking statements that are necessarily subject to various risks and uncertainties. Actual results may differ materially from those described in forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to, risks and uncertainties associated with: • wildfires that have occurred or may occur in the Utility’s service area, including the extent of the Utility’s liability in connection with the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, and future wildfires; • the timing and outcome of FERC and CPUC proceedings, including regarding ratemaking, cost recovery, and other matters; • the Utility’s ability to recover wildfire-related costs, including costs for the 2021 Dixie fire, from the Wildfire Fund and Continuation Account (including the Utility’s maintenance of a valid safety certificate and whether the Continuation Account has sufficient remaining funds), and through the WEMA and FERC TO rate cases; • the Utility’s implementation of its wildfire mitigation programs, including PSPS, EPSS, situational awareness and response, undergrounding, and the programs’ effectiveness; • the Utility’s ability to safely and reliably operate, maintain, construct, and decommission its facilities; • changes in the electric power and natural gas industries driven by technological advancements and a decarbonized economy; • a cyber incident, cybersecurity breach, or physical attack; • severe weather events, extended drought, and climate change, particularly their impact on the likelihood and severity of wildfires; • the impact of legislative and regulatory developments, including those regarding the Wildfire Fund, wildfires, the environment, California’s clean energy goals, the nuclear industry, extended operations at Diablo Canyon nuclear power plant, utilities’ transactions with their affiliates, municipalization, privacy, import tariffs, and taxes; • the outcome of self-reports, agency compliance reports, investigations, or other enforcement actions; • PG&E Corporation and the Utility’s substantial indebtedness, which may adversely affect their financial health and limit their operating flexibility; • the timing and outcome of PG&E Corporation’s and the Utility’s litigation, including securities class action claims and wildfire-related litigation; • the Utility’s ability to manage its costs effectively, timely recover costs through rates, and achieve projected savings and the extent of excess unrecoverable costs; • the impact of growing distributed and renewable generation resources, and changing customer demand for natural gas and electric services; • the Utility’s ability and cost to construct necessary infrastructure and the extent of customer demand for new load; and • the other factors disclosed in PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2025 the (Form 10-K"), and other reports filed with, or furnished to, the SEC, which are available on PG&E Corporation’s website at www.pgecorp.com and on the SEC’s website at www.sec.gov. Undefined, capitalized terms have the meanings set forth in the Form 10-K. Unless otherwise indicated, the statements in this presentation are made as of February 12, 2026. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation was attached to PG&E Corporation’s and the Utility’s joint Current Report on Form 8-K that was furnished to the SEC on February 12, 2026, and is also available on PG&E Corporation’s website at www.pgecorp.com. Forward-Looking Statements
3 Non-GAAP Core EPS1 36¢ Fourth Quarter 2025 Results …For Customers AND Investors Delivering 2025 And Tightening 2026 Range… Endnotes are included in the Appendix Guidance Delivered ► Delivered 4th year of double-digit EPS growth and raising 2026 midpoint ► Electric rates lower than 2024 ► Improved safety and reliability metrics ► Leaning in on SB 254 Phase 2 ► Amplifying Simple Affordable Model ► Detailing 5-year financing plan ► Final engineering of rate reducing large load projects ► Advancing wildfire safety goals Key Takeaways $1.50 Full Year 9%+ Annually 2027-2030 $1.64 - $1.66 2026 +10% +10% No Equity Need 2026-2030 20% by 2028 dividend payout Derisked 3.6 GW 11% 4th Year
4…Maximizing Customer Work, Building On Actual Results Simple, Affordable Model In Action1… Endnotes are included in the Appendix 2021A 2022A 2023A 2024A 2025A 26F 27F 28F 29F 30F +10% $1.002 +12% +11% +10% 9%+ 9%+ 9%+ 9%+ EPS Growth3 Storm Response and Interest Rates $1.10 $1.23 $1.36 Atmospheric Rivers Redeployment Redeployment Cost Performance and GRC Redeployment and Balance Sheet Strengthening Cost of Capital Redeployment & Equity Issuance Annual Guidance Headwinds and Tailwinds $1.50 +10% Redeployed $705M in O&M savings for the benefit of customers over four years Redeployment & De-Risking Equity Dilution & Reduced ROE O&M Savings
5 Planning For Wide-Ranging Wildfire Policy Reform… …April 1 Recommendations Kick Off Legislative Process California Earthquake Authority Appointed “Administrator” of the Wildfire Fund & Continuation Account. Will issue a comprehensive report to include specific recommendations, including, but not limited to, all the following: ► Insurance and Liability Reform ► Physical Mitigation and Community Impacts ► New Models and Customer Impact An improved wildfire framework, anchored in shared responsibility and accountability, can reduce catastrophic wildfire risk, accelerate recovery, lower costs, and distribute costs more fairly. Joint-IOU Abstract 83 Total number of contributions submitted for the CEA study from ~69 unique individuals/organizations Feb 6, 2026 Informational Webinar #2: Key Themes Dec 12, 2025 Stakeholder contributions due to CEA Mar 6, 2026 Informational Webinar #3: Study Findings April 1, 2026 CEA recommendations to Governor and Legislature Legislative Summer Recess July 3 – Aug 2, 2026 State Legislative Session Ends Aug 31, 2026
6…Reducing Ignitions And Fire Spread Mitigations Deployed With More To Come... PG&E Mitigations Delivering Results * As Reported By CAL FIRE 416 301 259 241 180 134 120 594 534 2,632 18,804 374 206 1,335 78 0 0 0 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 -100 100 300 500 700 900 1100 1300 1500 2017 2018 2019 2020 2021 2022 2023 2024 2025 Incidents ≥ 10 Acres in California * (all sources) Structures Destroyed in PG&E Reportable Fires in HFTD/HFRA During R3+ Conditions What’s New In 2026 EMBERPOINT Joint Venture1 Continuous Monitoring Capabilities 10-Year Undergrounding Filing Endnotes are included in the Appendix
7 Story Of The Year: Delivering Affordability Through Execution… …For Customers and California On January 1, PG&E lowered bundled electric rates for the 4th time in two years Actual Rates Are Down Bundled Residential Electric Rates 11% Lower Than January 2024 PG&E combined bill share of wallet 13% below the U.S. average1 Share of Wallet Customer Affordability Is Improving Exceeded O&M target for the 4th year in a row O&M Discipline Endnotes are included in the Appendix Delivered $1.4B in capital savings from 2023-2025 with $560M coming from Inspections, New Business, and Bundling Waste Elimination $1.4B 2024 Combined Electric and Gas Bill Share of Wallet PG&E 2.6% National Average 3.0% 0.8 0.9 1.0 1.7 2023 2024 2025 2030F Capital to Expense Ratio2
8…Amplified Simple, Affordable Model… Endnotes are included in the Appendix ACTUAL Subtotal Enablers O&M cost reduction (non-fuel)2 Electric load growth3 Other (including efficient financing)4 Customer Capital Investment Customer Bills: At or Below Assumed Inflation 2% 1% - 3% 2% ~9% 5% - 7% 2% - 4% OLD MODEL1 2% - 3% 2% - 4% 2% 9% - 10% 6% - 9% 1% - 3% - 4 - 6 - 10 NEW MODEL1 0
9…Economic Prosperity For Customers And California Enabling Affordable Load Growth… Data Center Pipeline1 Estimated Long-Term Customer Savings2: 1 GW = 1% Or More Electric Bill Reduction MWs September 2025 December 2025 Total 9,600 7,250 Application & Preliminary Engineering 7,950 3,600 Final Engineering 1,600 3,550 Construction 50 100 Endnotes are included in the Appendix Powering Our Future ► Hired Chief Commercial Officer ► Doubled Final Engineering and Construction MWs ► Energized first 40 MW data center under historic San Jose Implementation Agreement
10 Non-GAAP Core EPS1 Comparison... Endnotes are included in the Appendix …Delivered 2025 Guidance Endnotes are included in the Appendix 2024 Twelve Months Customer Capital … Operating & … Redeployment Equity Issuance Other -… 2025 Twelve Months Full Year 2025 vs. 2024 Customer Capital Investment2 Equity Dilution Other 2025 Twelve Months Operating & Maintenance Savings Re l yment2024 Twelve Months 7¢ ll r . (9¢) 20¢ $1.36 4¢ (8¢) $1.50 +10%
11…Extends Through 2030 Five-Year Capital Plan… Plus At Least $5B Customer Beneficial Investment Opportunities3 CPUC FERC XX% Avg Annual 2026-2030 % Already Authorized2 88% 84% 79% 74% Weighted Average Rate Base ($B)1 $73B 2026-2030 CPUC FERC CapEx ($B)1 Endnotes are included in the Appendix ~9% 12 13 14 17 19 21 57 62 67 72 77 85 69 75 81 89 96 106 2025A 2026F 2027F 2028F 2029F 2030F 2.5 3.9 4.6 4.9 4.1 9.9 9.5 10.8 11.4 11.9 12.4 13.4 15.4 16.3 16.0 2026F 2027F 2028F 2029F 2030F ► Transmission Upgrades: Data Centers and System Investments ► Transportation Electrification Capacity Investments ► Hydro and Storage ► IT and Automation 94% Includes $2.9B of SB 254 securitized capitalExcludes $2.9B of SB 254 securitized capital Amounts may not sum due to rounding
12…Supports Customer Capital Investment Without Common Equity Five-Year Financing Plan… (4) (12) 12 20 3 2 0 10 20 30 40 50 60 70 80 Cash from Operations Dividends Paid Utility LT Debt Maturities Utility LT Debt Refinanced Utility LT Debt Issuance SB 254 Securitization Parent Debt and Other Common Equity Issuance CapEx 1 $52 $73 Amount ($billions) 2026 – 2030 Five-Year Financing Plan 0 $0.6 $3.5 - $42026 Utility Debt (billions) Endnotes are included in the Appendix 0
13…Offer Incremental Affordability Opportunity SCALE RATING In v e s tm e n t G ra d e A2 A A3 A- Baa1 BBB+ Baa2 BBB Baa3 BBB- S u b -I n v e s tm e n t G ra d e Ba1 BB+ Ba2 BB Ba3 BB- B1 B+ Outlook Stable Credit Rating Improvements1… Positive Stable SCALE DEBT RATING Moody’s S&P/Fitch Moody’s S&P Fitch Present 2020 Corporation Secured Debt Rating Present 2020 Utility Secured Debt Rating Endnotes are included in the Appendix Financing Key Principles ✓ Plan conservatively ✓ Avoid equity dilution at low stock value ✓ Prioritize investment grade credit ✓ Sustain FFO/Debt in the mid-teens2 ✓ Improve cash flow with FERC capital ✓ Reach 20% dividend payout by 2028
14 O&M Cost Reduction Performance… …Track Record Of Exceeding 2% Reduction Target Endnotes are included in the Appendix Examples of O&M Cost Reductions (Non-Fuel)1 Resource Management Efficiencies and Insurance Capital Conversion Planning, Execution, Automation and AI Net Cost Increases Net Savings Percent Savings $510 5½% (60)3 130 --2 350 $90 (millions) 2023 Actual $340 4% (290) 155 45 370 $60 (millions) 2024 Actual $160 - $300 2% - 4% (105) - (125) 110 - 140 45 - 150 65 $45 - $70 (millions) LONG-TERM PLAN4 $220 2% (250) 170 80 135 $85 (millions) 2025 Actual 2½%
15…To Deliver For Customers Working With Policymakers And Stakeholders… Constructive Legislation SB 884, SB 846, SB 410 4-Year Revenue Certainty 3-Year CoC Cycle w/ ROE Adjustment Mechanism FERC Formula Rate Regulatory and Policy Environment Dec 2025 CPUC 10-Year Undergrounding Plan Guidelines Dec 2025 2026 Cost of Capital Final Decision Dec 2024 2024 Safety Certificate Issued Sept 19, 2025 Governor Newsom signs SB 254 May 2025 2027-2030 GRC Filing Q3 2025 SB 410 Revised Cost Caps Final Decision Sept 30, 2025 Executive Order to expedite the next phase of SB 254 Apr 1, 2026 Wildfire Fund Administrator Report and Recommendations Aug 31, 2026 2026 Legislative Session Ends Q1 2026 2025 Safety Certificate Nov 2026 Kincade and Dixie Cost Recovery Proposed Decision Apr 2026 2027 GRC Evidentiary Hearings Q3 2026 10-Year Undergrounding Filing
16…Benefits Customers AND Investors 2023A 2024A 2025A Future Customer Investment Rate Base $58B $63B $69B CA Regulatory Ranking (RRA) Average/1 Average/1 Average/1 Above Average Affordability Enablers Non-Fuel O&M Reduction1 5½% 4% 2½% 2% - 4% Capital to Expense Ratio2 0.8 0.9 1.0 1.7 Credit Ratings BB- /Ba2 BB /Ba1 BB /Ba1 Investment Grade Consistent Performance Non-GAAP Core EPS Growth3 12% 11% 10% 2026: 10% 2027 - 2030: 9%+ Operating Cashflow $4.7B $8.0B $8.7B $10B+ FFO/Debt4 13.7% 14.0% Mid-teens Dividend Payout Ratio5 0% 3% 7% 20% by 2028 Risk Reduction Safety Certification Filed 12/2/25 Financial Common Dividend / Fire Victim Trust Exit Equity Issuance / Dividend Guidance 2026-2030 Financial Plan Stronger Valuation Differentiated Performance… ~9%6 Endnotes are included in the Appendix
17…And Providing Differentiated Growth For Investors Investing In California’s Prosperity… Commitment to California’s Prosperity and Growth 10% 12% 11% 10% 10% 9%+ 9%+ 9%+ 9%+ 22A 23A 24A 25A 26F 27F 28F 29F 30F $B 0.9 1.0 1.7 2.0 2.9 PG&E 2024 PG&E 2025 PG&E 2030F 2024 Peer Avg 2024 Peer Top Decile Premium Growth Capital to Expense Ratio3 ~9% Avg Annual Growth Rate Base Non-GAAP Core EPS2 + DPS Growth 75 81 89 96 106 26F 27F 28F 29F 30F Endnotes are included in the Appendix 5-Year Capital Plan (2026-2030) invests $73B in California, supporting grid safety and reliability, while prioritizing affordability for customers Critical partner to California, the world's 4th largest economy,1 delivering energy and driving economic growth and development Powering California’s expanding grid — 25 GWs mainly battery storage and solar added statewide since 2020 Collaborating with other utilities and local and state agencies to prevent, forecast, and improve response protocols for emergencies
18 Physical and Financial Safety Decarbonized Energy System Affordable and Resilient Energy Q&A
Appendix 1 Presentation Endnotes 19
20 Appendix 1: Presentation Endnotes Slide 3: Delivering 2025 And Tightening 2026 Range 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit E regarding non-GAAP financial measures. PG&E Corporation is unable to provide GAAP guidance or present a quantitative reconciliation of forward-looking non-GAAP core earnings, non-GAAP core EPS, or non-GAAP core EPS growth (including any ratios based thereon, including dividend payout ratios) without unreasonable effort because specific line items, which may be significant, are not estimable. For instance, amortization of the Wildfire Fund contribution asset, the impacts of regulatory decisions, special tax items, and wildfire-related costs, net of recoveries, are difficult to predict due to various factors outside of management’s control. Slide 4: Simple, Affordable Model In Action 1. Gray line illustrates headwinds and tailwinds to delivering on annual non-GAAP core EPS guidance, as well as the impact of PG&E Corporation's and the Utility's responses to such developments. For instance, headwinds may include cost productivity below budget; unfavorable regulatory, legislative, or tax outcomes; interest expense; or assumptions or planning regarding the foregoing. Tailwinds may include cost productivity above budget; favorable regulatory, legislative, or tax outcomes; interest income; or assumptions or planning regarding the foregoing. Redeployment includes accelerating the timing of when expenses are incurring, increasing the amount of work performed, and cost increases relative to the prior year. 2. Non-GAAP core EPS for the full year 2020 was $1.61 based on weighted average of approximately 1.257 billion shares outstanding. For illustrative purposes, 2020 non-GAAP core EPS has been recast using common shares outstanding on a fully diluted basis as of December 31, 2020 of approximately 2.124 billion shares. Non-GAAP core EPS for the full year 2021 was $1.00 per share on a fully diluted basis and $1.08 using a basic share count. The impact of dilution was $(0.08) per share. See Appendix 9, Exhibit A of the earnings presentation for the fourth quarter and full year 2021, available here, for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share for such years and Appendix 9, Exhibit H regarding non-GAAP financial measures. 3. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit E regarding non-GAAP financial measures. Slide 6: Mitigations Deployed With More To Come 1. Contributions from the Utility to EMBERPOINT are subject to regulatory approval. EMBERPOINT is not the same company as PG&E, the utility, and is not regulated by the California Public Utilities Commission. You do not have to buy EMBERPOINT 's products in order to continue to receive quality regulated services from the utility. Slide 7: Story Of The Year: Delivering Affordability Through Execution 1. Analysis based on 2024 data from the US Energy Information Administration and the US Census Bureau. 2. Represents Capital expenditures divided by Operating and Maintenance, as disclosed in the applicable Annual Report on Form 10-K. Slide 8: Simple, Affordable Model 1. These numbers are illustrative approximations and should not be interpreted as a guarantee of future performance. 2. The Utility’s cost reduction strategies include increased efficiency and waste elimination driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to improve its capital-to-expense ratio, and an improved organizational design. Factors that may cause the Utility’s actual results to differ materially from i ts forecasts include whether the Utility can control its operating costs within the authorized levels of spending and timely recover its costs through rates; whether the Utility can achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons. See “Forward-Looking Statements” on slide 2. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Utility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. Reductions available for redeployment. 3. Expected drivers of forecasted electric load growth include data centers, electric vehicle adoption, and building electrification. 4. Factors that may cause the Utility’s actual results to differ materially from its forecasts include the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms; their ability to raise financing through securitization transactions; actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings; the supply and price of electricity, natural gas, and nuclear fuel ; and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation, and PG&E Corporation’s and the Utility’s ability to obtain efficient tax treatment. See “Forward-Looking Statements” on slide 2. Slide 9: Enabling Affordable Load Growth 1. Scope includes applications received to serve new data center load, requesting 20 megawatts of power or more. Application & Preliminary Engineering goes from application to selection of service option and requires a study fee. Final Engineering begins after approval of preliminary engineering study (includes engineering, ordering long lead materials & permitting). Final Engineering requires payment commensurate with work performed. Construction ends with customer energization. 2. Factors that may cause the Utility’s actual results to differ materially from this forecast include the Utility's interconnec tion costs, the amount of power used by customers, the price of power, and the amount of cost recovery approved in the Utility's ratemaking proceedings. Assumes additional power supply costs from serving new data center load are not borne by other customers. See “Forward-Looking Statements” on slide 2. Slide 10: Non-GAAP Core EPS Comparison 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit E regarding non-GAAP financial measures. 2. Year-over-year changes in customer capital investment were primarily due to the earnings impact of higher rate base, partially offset by the change in the Utility’s authorized return on equity from 10.7% to 10.28%. Slide titles are hyperlinks
21 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 11: Five-Year Capital Plan 1. Rate base point estimates reflect authorized capital expenditures from the 2023 GRC final decision, SB 410, Oakland headquarters Petition for Modification, Gas AMI, 2023 WMCE, to other CPUC-jurisdictional approvals (including the full amount recoverable through a balancing account where applicable), above-authorized capital spend that will support the Utility's plan, including strategic capital investments in undergrounding, wildfire mitigation, billing modernization, and mobile home parks, along with a forecast of our 2027 GRC filing. Weighted average rate base excludes Construction work in progress (CWIP) and non-earnings rate base related to AB 1054 and SB 254. 2. Percentage already authorized for CPUC-jurisdictional rate base holds constant the 2026 adopted CapEx for 2027 – 2030, includes SB 410 and Oakland headquarters Petition for Modification, Gas AMI, 2023 WMCE, and assumes FERC- jurisdictional rate base is equivalent to amounts requested in the formula rate through Transmission Owner rate proceedings for years 2025 through 2030. 3. Investment opportunities of at least $5 billion are not reflected in the CapEx or rate base numbers. Slide 12: Five-Year Financing Plan 1. Excludes employee compensation. Slide 13: Credit Rating Improvements 1. A securities rating is not a recommendation to buy, sell, or hold securities and may be subject to revision or withdrawal at any time. 2. FFO/Debt is not calculated in accordance with GAAP. A reconciliation is not provided for future period FFO/Debt because PG&E Corporation is not able to estimate the impact of specific line items, which have the potential to significantly impact the company’s FFO/Debt in future periods, and so a reconciliation is not available without unreasonable effort. Slide 14: O&M Cost Reduction Performance 1. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Utility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. Reductions available for redeployment. 2. Denoted amount is not material. 3. A higher discount rate used to measure the projected benefit costs at December 31, 2023 compared to December 31, 2022 resulted in lower pension and other post-retirement benefits service cost in the amount of $321 million. This decrease is embedded in 2023 net cost increases. 4. These numbers are illustrative approximations and should not be interpreted as a guarantee of future performance. See “Forward-Looking Statements” on slide 2. Slide 16: Differentiated Performance 1. The Utility’s cost reduction strategies include increased efficiency driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to convert expenses to capital expenditures, and an improved organizational design. Factors that may cause the Utility’s actual results to differ materially from its forecasts include whether the Utility can control its operating costs within the authorized levels of spending and timely recover its costs through rates; whether the Utility can achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Ut ility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. Reductions available for redeployment. See “Forward-Looking Statements” on slide 2. 2. Represents Capital expenditures divided by Operating and maintenance, as disclosed in the applicable Annual Report on Form 10-K. 3. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit E regarding non-GAAP financial measures. 4. FFO/Debt is not calculated in accordance with GAAP. See Appendix 3, Exhibit D for a reconciliation of Operating income and Total debt on a GAAP basis to FFO/Debt and Appendix 3, Exhibit E regarding non-GAAP financial measures. FFO/Debt for 2023 has not been disclosed. A reconciliation is not provided for future period FFO/Debt because PG&E Corporation is not able to estimate the impact of specific line items, which have the potential to significantly impact the company’s FFO/Debt in future periods, and so a reconciliation is not available without unreasonable effort. 5. Dividend payout ratio is determined by dividing the total dividends per share paid over the fiscal year by non-GAAP core earnings per share. 6. Based on average annual growth from 2026 through 2030.
22 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 17: Investing In California's Prosperity 1. Source: https://www.gov.ca.gov/2025/04/23/california-is-now-the-4th-largest-economy-in-the-world/ 2. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit E regarding non-GAAP financial measures. 3. Represents Capital expenditures divided by Operating and maintenance, as disclosed in the applicable Annual Report on Form 10-K. Slide 24: Appendix 2: 2026 Factors Impacting Earnings 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit E regarding non-GAAP financial measures. 2. The low end of the share count range assumes no PG&E Corporation mandatory convertible preferred shares (MCPs) have converted into common stock. The high end of the range assumes all MCPs have converted based on a PG&E Corporation common stock price of $20.55, consistent with the prospectus supplement filed December 3, 2024. 3. 2026 equity-earning weighted-average rate base reflects 2023 GRC final decision and the TO21 decision. 4. The capital structure of an investor-owned utility is the proportional authorization of shareholders’ equity and debt that comprise a company’s long-range financing or its capitalization. The CPUC currently authorized capital structure is comprised of 47.5% long-term debt, 0.5% preferred equity, and 52% common equity. The FERC currently authorized capital structure is comprised of 49.70% long-term debt, 0.3% preferred, and 50% common equity. 5. Non-GAAP core earnings assumptions include no 2026 impacts from changes in the federal tax code. 6. Unrecoverable net interest includes PG&E Corporation long-term debt, Wildfire Fund contribution debt financing, and other interest above authorized, netted against the Utility’s balancing account interest. Slide 30: Appendix 2: Existing Protections Enhanced Pending Broader Policy Update 1. Prior to the enactment of AB 1054, utilities bore the burden of proving that their conduct was reasonable in order to obtain recovery of costs through rates. AB 1054 changed the standard so that the conduct of a utility is deemed reasonable unless a party to the proceeding creates a serious doubt as to the reasonableness of the utility’s conduct. Reasonable conduct is not limited to the optimum practice, method, or act to the exclusion of others, but rather encompasses a spectrum of possible practices, methods, or acts consistent with utility system needs, the interest of the ratepayers, and the requirements of governmental agencies of competent jurisdiction. 2. For fires in any calendar year. 3. Cap does not apply if Utility found to have acted with conscious or willful disregard of the rights and safety of others. Amount reflects 2025 electric transmission and distribution equity rate base. Slide 32: Appendix 2: SB 846 Diablo Canyon Legislation 1. The pre-extension period extended through the scheduled retirement dates of November 2024 and August 2025 for Units 1 and 2, respectively. 2. The extension period covers the additional 5-year life for each Unit.
Appendix 2 Supplemental Earnings Materials 23
24 2026 Factors Impacting Earnings Endnotes are included in the Appendix $1.64 - $1.66 Non-GAAP Core EPS1 Diluted Shares 20262 2,210M - 2,295M Key Ranges Weighted Average Rate Base3 CPUC 9.98% 52% $62B FERC 10.38% 50% $13B Total Rate Base $75B Authorized Return on Equity Key Factors Affecting Non-GAAP Core Earnings5 ($ millions after tax) Unrecoverable net interest6 $325 - $375 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs Equity Ratio4 Rate Base Changes from prior quarter noted in blue text
25 Expected Recovery Of Wildfire-Related Costs $0.8B Approved Recovery Status as of December 31, 2025 $0.9B Pending $0.6B Yet To Be Filed $2.3B Total 2023 WGSC $56M AB1054 Dixie Kincade $826M
26 Physical Risk Mitigations Making Our System Safer Every Day HFTD + HFRA Weather-Normalized Ignition Rates R3+ per 100k Circuit Mile Days Weather-Normalized Ignition Rate 3.23 2.67 2.25 2.76 1.93 0.95 0.93 1.41 1.10 2017 2018 2019 2020 2021 2022 2023 2024 2025 EPSS Implemented Mid-2021 24 12 7 8 6 4 5 9 1 2017 2018 2019 2020 2021 2022 2023 2024 2025 Significant Reduction in PG&E Ignitions Leading To Fires > 10 Acres PG&E R3+ Ignitions > 10 Acres in HFTD + HFRA
Internal 27 PG&E’s $73B Capital Plan Offers A Wide Spectrum Of Customer Benefits $3B$4B $8B $20B $38B Electric Distribution Electric Transmission Technology & Other Gas T&D Power Generation 2026 – 2030 CapEx By Functional Area $20B $16B $23B $14BSafety Capacity & New Business Reliability 2026 – 2030 CapEx By Customer Benefits Resiliency
28 Wildfire Fund Continuation Account For Future Wildfires Customer Annual Charge 2036-2045 ~$900M per year PG&E Monthly Bill: ~$3*** Utility Contingent Funding Over 5 years only if needed PG&E $373M per year Utility Annual Funding 2029-2045 $300M per year PG&E $144M $10.5 $9.0 $3.0 $5.1 $3.9 $7.5 > $21.0 B $18.0 B AB 1054 Wildfire Fund Continuation Account ** * Half of any unpaid contingent funding provided as a customer bill credit ** Bonding authority available *** Based on current assumptions Utility Upfront Funding 2019-2020 PG&E $4.8B Utility Annual Funding 2019-2028 $300M per year PG&E $193M Customer Annual Charge 2019-2035 ~$900M per year PG&E Monthly Bill: ~$3 * > **
29 SB 254: Improved Upon California Wildfire Risk Framework First step following January 2025 fires and building on existing AB 1054 foundation Creates new Wildfire Fund Continuation Account providing $18B for future wildfires Retains key fund benefits: rate smoothing, liquidity for victims, and disallowance cap Gives utilities new Right of First Refusal over sales of insurance subrogation rights Allows early securitization option for 2025 fires preceding effective date of SB 254 Wildfire Fund Continuation Account: Sets stage and parameters for wide-ranging wildfire policy reform in 2026 session Rebalanced PG&E share lowered by 25% to 47.85% (from 64.20%) Principled Utility funding counts towards future disallowance Flexible Improved Disallowance cap now based on year of ignition Utility funding spread over time rather than upfront * The Governor signed SB 254 on September 19, 2025. The utilities have elected to participate in the Continuation Account. New Features
30 Existing Protections Enhanced Pending Broader Policy Update Protections Offered Under AB 1054 & SB 254 ▪ Liquidity available as soon as claims paid exceed $1B2 ▪ SB 254 establishes Continuation Account for future fires ▪ Securitization can be authorized for 2025 fires prior to SB 254 ▪ Utility Right of First Refusal over sales of subrogation rights Liquidity Bolstered Available when needed ▪ Utility conduct presumed prudent with annual safety certificate in place ▪ Enhanced cost recovery standard distinct from Fund ▪ Customer-funded self-insurance up to $1B began in 2023 Cost Recovery Unchanged Improved prudency standard1 Reimbursement Improved Disallowance cap retained ▪ If prudent: Fund reimbursement not required ▪ If imprudent: Utility reimburses Fund; SB 254 contributions count against disallowance ▪ Disallowance cap (20% of electric T&D equity rate base as of year of ignition) reduced for reimbursements for other fires within 3 years3 Physical Risk Reduction Drives Financial Protections 1 Physical Risk Mitigations 2 Approved Wildfire Mitigation Plan (WMP) 3 Wildfire Safety Certification Endnotes are included in the AppendixEndnotes are included in the ppendix
31 California Wildfire Fund Mechanics Fund is not reimbursed Partial or full reimbursement; net of utility contributions under SB 254 (reduced for reimbursements for other fires within 3 years) CPUC evaluates if the Covered Utility’s conduct was reasonable Covered Utility files cost recovery application at the CPUC for claims paid from the Fund Covered Utility seeks payment from the Fund for eligible claims >$1B Disallowed costsAllowed costs Claims filed against Covered Utility Filing after “substantially all” claims have been paid 12-month CPUC review with possible 6-month extension Customer funded self-insurance covers first $1B of claims Cap = 20% of T&D equity rate base @ time of ignition
32 SB 846 Diablo Canyon Legislation Cost Recovery 2022-20251 2025-20302 ▪ Ongoing O&M and rate base recovery through the GRC ▪ $1.4B in state funding available to support extended operations • Up to $1.1B in extension costs to be reimbursed from DOE Civil Nuclear Credit program • Up to $300M available to invest in business through a $7/MWh transition fee starting 9/2/22 ▪ $100M/year in lieu of traditional rate base return ▪ Annual automatic true-up mechanism for costs ▪ $13/MWh performance fee upside to be deployed for customer benefit Pre-Extension Period Extension Period 9/2/22 Governor Newsom signed SB 846 1/11/24 Finalized terms with DOE for up to $1.1B via the Civil Nuclear Credit Program 10/18/22 Executed $1.4B loan agreement with DWR 3/2/23 NRC approved exemption request allowing continued operations at DCPP 11/7/23 Filed for NRC license renewal 12/14/23 CPUC final decision conditionally approving extended operations 12/19/23 NRC determined license renewal application sufficient 6/25 NRC Environmental Impact Statement and Safety Evaluation Report Endnotes are included in the Appendix 2026 Remaining state permit NRC license renewal
33 Physical Risk Mitigation Progress Then & Now 2017 EPSS PSPS Undergrounding Program HD Cameras Weather Stations Wildfire Mitigation Plan SITUATIONAL AWARENESS High-Definition Cameras with AI Capability Weather Stations Hazard Awareness Warning Center Advanced Meteorology and Fire Science Models 698 CAMERAS INSTALLED 1,620 STATIONS INSTALLED 24/7/365 MONITORING ASSET IMPROVEMENTS Undergrounding System Hardening Sectionalizing Devices Trees Removed 1,210 MILES COMPLETED * 2,552 MILES COMPLETED ** 1,688 DEVICES INSTALLED 4.3M TREES REMOVED OPERATIONAL MITIGATIONS EPSS PSPS Partial Voltage Force Out Safety and Infrastructure Protection Teams Transmission Operational Controls Downed Conductor Detection 2019 – December 31, 2025 * Undergrounding Program started in 2021 ** System Hardening totals include data starting in 2018 2025
34 Regulatory Case/Filing Docket Status as of February 2026 Expected Milestones 2027 GRC A.25-05-009 ▪ 2027 GRC Application filed 5/15/25 Final Decision May 2027 2025 and 2026 Energization Cost Caps (SB 410) R.24-01-018 ▪ Motion to revise 2025 and 2026 Energization Cost Caps filed 10/4/24 ▪ Final Decision 8/28/25 TO21 ER24-96-000 ▪ Application filed 10/13/2023 ▪ Settlement filed 3/21/25 ▪ Final Decision 8/5/25 2026 Cost of Capital A.25-03-010 ▪ Application filed 3/20/25 ▪ Final Decision 12/18/25 2022 WMCE A.22-12-009 ▪ Application filed 12/15/22 ▪ Interim rate relief granted 6/8/23 ▪ Settlement filed 12/22/23 (excludes WMBA and VMBA) ▪ Final Decision 9/18/25 2023 WMCE A.23-12-001 ▪ Application and interim rate relief request filed 12/1/23 ▪ Interim rate relief Final Decision received 9/12/24 ▪ Settlement filed 6/2/25 ▪ Final Decision 2/5/26 2023 Wildfire Mitigation Plan 2023-2025-WMPs ▪ Submitted 3/27/23 ▪ Final Decision by OEIS received 12/29/23 ▪ CPUC ratified 2/15/24 ▪ 2025 Update filed 4/2/24, Supplemental 2025 Update filed 7/5/24 ▪ Final Decision by OEIS received 11/19/24 2026 Wildfire Mitigation Plan 2026-2028-WMPs ▪ Submitted 4/4/25 ▪ Final Decision by OEIS received 2/5/26 2025 Safety Certificate 2025-SCs ▪ Filed 12/2/25 No later than 90 days after submission Wildfire and Gas Safety Costs A.23-06-008 ▪ Filed 6/15/23 ▪ Interim rate relief granted 3/7/24 Electric Rule 30 A.24-11-007 ▪ Application filed 11/21/24 ▪ Final Decision on motion for interim implementation 7/24/25 Changes from prior quarter noted in blue text Regulatory Progress
Appendix 3 Supplemental Non-GAAP Information 35
36 Supplemental Earnings Materials Exhibit Title Slide (Link) Exhibit A Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with GAAP to Non-GAAP Core Earnings Slides 37-40 Exhibit B Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share (“EPS”) Slide 41 Exhibit C GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation Slide 42 Exhibit D Reconciliation of PG&E Corporation's Operating Income and Total Debt in Accordance with GAAP to Adjusted Funds from Operations (“FFO”) and Adjusted Total Debt Slide 43 Exhibit E Non-GAAP Financial Measures Slide 44
37 Three Months Ended December 31, Year Ended December 31, Earnings Earnings per Common Share Earnings Earnings per Common Share (in millions, except per share amounts) 2025 2024 2025 2024 2025 2024 2025 2024 PG&E Corporation’s GAAP earnings/EPS, diluted $ 642 $ 647 $ 0.29 $ 0.30 $ 2,593 $ 2,475 $ 1.18 $ 1.15 Non-core items: (1) Amortization of Wildfire Fund contribution (2) 58 63 0.03 0.03 253 276 0.11 0.13 Bankruptcy and legal costs (3) 6 2 — — 41 35 0.02 0.02 Investigation remedies (4) 16 14 0.01 0.01 112 55 0.05 0.03 Prior period net regulatory impact (5) 68 45 0.03 0.02 190 28 0.09 0.01 SB 901 securitization (6) (3) (7) — — 26 24 0.01 0.01 StanPac settlement (7) — 84 — 0.04 — 84 — 0.04 Tax-related adjustments (8) (5) (213) — (0.10) (5) (143) — (0.07) Wildfire-related costs, net of recoveries (9) 5 22 — 0.01 97 89 0.04 0.04 PG&E Corporation’s non-GAAP core earnings/EPS (10) $ 787 $ 658 $ 0.36 $ 0.31 $ 3,307 $ 2,923 $ 1.50 $ 1.36 All amounts presented in the table above and footnotes below are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2025 and 2024, except for certain costs that are not tax deductible. Amounts may not sum due to rounding. Fourth Quarter and Full Year, 2025 vs. 2024 (in millions, except per share amounts) (1) “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods, consisting of the items listed in the table above. See Exhibit E: Non-GAAP Financial Measures. Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings
38 Fourth Quarter and Full Year, 2025 vs. 2024 (in millions, except per share amounts) (3) PG&E Corporation and the Utility recorded costs of $8 million (before the tax impact of $2 million) and $57 million (before the tax impact of $16 million) during the three months and year ended December 31, 2025, respectively, related to costs to resolve proof of claims filed in PG&E Corporation’s and the Utility’s Chapter 11 filing. (2) The Utility recorded costs of $81 million (before the tax impact of $23 million) and $352 million (before the tax impact of $98 million) during the three months and year ended December 31, 2025, respectively, associated with the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability. For more information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements in the Form 10-K. Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings (4) Includes costs associated with the decision different for the order instituting investigation (“OII”) related to the 2017 Northern California Wildfires and 2018 Camp Fire (“Wildfires OII”), the system enhancements related to the locate and mark OII, restoration and rebuilding costs for the town of Paradise, and the settlement agreement resolving the Safety and Enforcement Division’s investigation into the 2020 Zogg fire, as shown below. (in millions) Three Months Ended December 31, 2025 Year Ended December 31, 2025 Wildfires OII disallowance and system enhancements $ 7 $ 40 Locate and mark OII system enhancements — 1 Paradise restoration and rebuild (1) 2 2020 Zogg fire settlement 8 74 Investigation remedies $ 14 $ 117 Tax impacts 2 (6) Investigation remedies (post-tax) $ 16 $ 112
39 Fourth Quarter and Full Year, 2025 vs. 2024 (in millions, except per share amounts) (in millions) Three Months Ended December 31, 2025 Year Ended December 31, 2025 2011 GT&S rate case $ — $ (19) TROW adjustment (59) (59) 2022 WMCE decision — 188 2023 WMCE decision 153 153 Prior period net regulatory impact $ 94 $ 263 Tax impacts (26) (73) Prior period net regulatory impact (post-tax) $ 68 $ 190 Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings (6) The Utility recorded benefits of $4 million (before the tax impact of $1 million) and costs of $36 million (before the tax impact of $10 million) during the three months and year ended December 31, 2025, respectively, related to the charge for the establishment of the SB 901 securitization regulatory asset and the SB 901 securitization regulatory liability associated with revenue credits funded by the net operating loss monetization, as well as any earnings-impacting investment losses or gains associated with investments related to the contributions to the Customer Credit Trust and additional contributions to the Customer Credit Trust as a result of the decision voted out on July 24, 2025. (5) Includes adjustments to expenses (revenues) associated with the recovery of capital expenditures from 2011 through 2014 above amounts adopted in the 2011 GT&S rate case per the CPUC decision dated July 14, 2022, the 2022 WMCE decision dated September 18, 2025, and the 2023 WMCE decision dated February 5, 2026 as well as adjustments to interest associated with transmission right of way (TROW) costs incurred between 2017 and 2024 as shown below. (7) Includes probable costs to resolve legacy gas transportation issues related to its affiliate Standard Pacific Gas Line Incorporated.
40 Fourth Quarter and Full Year, 2025 vs. 2024 (in millions, except per share amounts) (10) “Non-GAAP core earnings” and "Non-GAAP core EPS" are non-GAAP financial measures. See Exhibit E: Non-GAAP Financial Measures. Undefined, capitalized terms have the meanings set forth in the Form 10-K. (9) Includes costs to resolve third-party claims, net of recoveries, for the 2019 Kincade fire and 2021 Dixie fire, inclusive of outside counsel fees, as shown below. (in millions) Three Months Ended December 31, 2025 Year Ended December 31, 2025 2019 Kincade fire $ 1 $ 117 2021 Dixie fire 6 18 Wildfire-related costs, net of recoveries $ 7 $ 135 Tax impacts (2) (38) Wildfire-related costs, net of recoveries (post-tax) $ 5 $ 97 Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles ("GAAP") to Non-GAAP Core Earnings (8) The Utility recorded tax benefits of $5 million during the three months and year ended December 31, 2025 associated with certain customer bill credits issued in connection with the San Bruno natural gas explosion that occurred in 2010.
41 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2025 and 2024. Amounts may not sum due to rounding. (1) See Exhibit A for reconciliations of (i) earnings on a GAAP basis to non-GAAP core earnings and (ii) EPS on a GAAP basis to non-GAAP core EPS. (2) Represents operating and maintenance savings for various initiatives during the three months and year ended December 31, 2025. Examples include reduced contract spend through contract rationalization and reduction in overhead expense. (3) Represents redeployment of operating and maintenance savings to invest in various programs including those that support risk mitigation, customer service operations, and enterprise service delivery during the three months and year ended December 31, 2025. (4) The earnings impact represents the dividend payment for the mandatory convertible preferred (MCP) issued in 2024. The earnings per common share figures represent the impact of both the MCP dividend and dilution resulting from the common equity issued in December 2024 for the three months and year ended December 31, 2025. (5) Represents the impact to earnings for items considered timing-related such as taxes, other miscellaneous items such as interest expense and one time items, as well as a tax method change during the three months and year ended December 31, 2025. Fourth Quarter 2025 vs. 2024 Year to Date 2025 vs. 2024 Earnings Earnings per Common Share Earnings Earnings per Common Share 2024 Non-GAAP Core Earnings/EPS (1) $ 658 $ 0.31 $ 2,923 $ 1.36 Customer capital investment 40 0.02 160 0.07 Operating & maintenance savings (2) 257 0.12 445 0.20 Redeployment (3) (138) (0.06) (196) (0.09) Equity dilution (4) (24) (0.02) (96) (0.08) Other (5) (6) — 71 0.04 2025 Non-GAAP Core Earnings/EPS (1) $ 787 $ 0.36 $ 3,307 $ 1.50 Fourth Quarter and Full Year 2025 vs. 2024 (in millions, except per share amounts) Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share ("EPS") Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share ("EPS")
42 Year Ended December 31, (in millions) 2025 2024 PG&E Corporation’s Net Income on a GAAP basis $ 2,703 $ 2,512 Income tax provision (benefit) (280) (200) Other income, net (182) (300) Interest expense 3,028 3,051 Interest income (520) (604) Operating Income $ 4,749 $ 4,459 Depreciation, amortization, and decommissioning 4,634 4,189 Amortization of Wildfire Fund contribution 352 383 SB 901 securitization 36 33 Investigation remedies 118 59 Prior period net regulatory impact 263 39 Wildfire-related costs, net of recoveries 135 123 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 10,286 $ 9,285 Fourth Quarter and Full Year, 2025 vs. 2024 (in millions) Amounts may not sum due to rounding. “Non-GAAP Adjusted EBITDA” is a non-GAAP financial measure. Exhibit C: GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation
43 Exhibit D: Reconciliation of PG&E Corporation's Operating Income and Total Debt in Accordance with GAAP to Adjusted Funds from Operations ("FFO") and Adjusted Total Debt 2025 2024 (in millions) (in millions) Operating income $ 4,749 $ 4,459 Depreciation, amortization, and decommissioning 4,634 4,189 SB 901 securitization charges, net 35 33 Wildfire-related claims, net of recoveries 100 94 Adjustments: Cash interest (1) (2,665) (2,421) ARO accretion 290 269 Operating lease fixed cost 115 116 Other 37 (22) Adjusted FFO $7,295 $ 6,717 2025 2024 (in millions) (in millions) Long-term debt $ 57,387 $ 53,569 Long-term debt, classified as current 821 2,146 Short-term borrowings 2,675 1,523 Adjustments: Cash and cash equivalents (713) (940) Securitized debt (10,145) (10,367) Junior subordinated notes (750) (750) Power purchase commitments debt equivalents 1,377 1,393 ARO debt 955 1,273 Operating lease liabilities 450 524 Financing lease liabilities 2 581 Noncontrolling Interest - Preferred Stock of Subsidiary 126 126 Adjusted Total Debt $ 52,185 $ 49,077 Adjusted FFO Calculation Adjusted Total Debt Calculation Adjusted FFO = $7,295 = 14.0% Adjusted Total Debt $52,185 2025 Adjusted FFO to Total Debt Ratio Amounts may not sum due to rounding. “Adjusted FFO,” “Adjusted Total Debt,” and “Adjusted FFO to Total Debt” are non-GAAP financial measures. (1) Cash interest is from PG&E Corporation’s Consolidated Statements of Cash Flows, Cash paid for interest, net of amounts capitalized
44 Non-GAAP Core Earnings and Non-GAAP Core EPS “Non-GAAP core earnings” and “Non-GAAP core EPS,” also referred to as “non-GAAP core earnings per share,” are non-GAAP financial measures. Non-GAAP core earnings is calculated as income available for common shareholders, diluted, less non-core items. “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods, consisting of the items listed in Exhibit A. Non-GAAP core EPS is calculated as non-GAAP core earnings divided by common shares outstanding on a diluted basis. PG&E Corporation discloses historical financial results and provides guidance based on “non-GAAP core earnings” and “non-GAAP core EPS” in order to provide measures that allow investors to compare the underlying financial performance of the business from one period to another, exclusive of non-core items. PG&E Corporation and the Utility use non-GAAP core earnings and non-GAAP core EPS to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating planning, and employee incentive compensation. PG&E Corporation and the Utility believe that non-GAAP core earnings and non-GAAP core EPS provide additional insight into the underlying trends of the business, allowing for a better comparison against historical results and expectations for future performance. PG&E Corporation is unable to provide GAAP guidance or present a quantitative reconciliation of forward-looking non-GAAP core earnings, non-GAAP core EPS, or non-GAAP core EPS growth (including any ratios based thereon, including dividend payout ratios) without unreasonable effort because specific line items, which may be significant, are not estimable. For instance, amortization of the Wildfire Fund contribution asset, the impacts of regulatory decisions, special tax items, and wildfire-related costs, net of recoveries, are difficult to predict due to various factors outside of management’s control. Non-GAAP core earnings and non-GAAP core EPS are not substitutes or alternatives for GAAP measures such as consolidated income available for common shareholders and may not be comparable to similarly titled measures used by other companies. Exhibit E: Non-GAAP Financial Measures