EX-99.2 3 q225earningspresentation.htm EX-99.2
2025 SECOND QUARTER EARNINGS July 31, 2025 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 2025 non-GAAP core earnings), debt and equity issuances, refinancing activity, rate base growth, capital expenditures, cash flow, cost savings, customer bills, wildfire risk mitigation, wildfire-related cost recovery, dividends, load growth, operating and maintenance costs, financing efficiency, capital to expense ratio, 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. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. 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 Utility’s ability to recover wildfire-related costs, including costs for the 2021 Dixie fire, from the Wildfire Fund (including the Utility’s maintenance of a valid safety certificate and whether the Wildfire Fund 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 timing and outcome of FERC and CPUC proceedings, including regarding ratemaking, cost recovery, and other matters; • 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 tax treatment of certain assets and liabilities, including whether PG&E Corporation or the Utility undergoes an “ownership change” that limits certain tax attributes; • the impact of growing distributed and renewable generation resources, and changing customer demand for its 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, 2024, their joint Quarterly Form 10-Q for the quarter ended June 30, 2025 (the “Form 10-Q”), and other reports filed with 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-Q. Unless otherwise indicated, the statements in this presentation are made as of July 31, 2025. 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 July 31, 2025, and is also available on PG&E Corporation’s website at www.pgecorp.com. Forward-Looking Statements

3 Non-GAAP Core EPS1 31¢ Second Quarter 2025 Results …For Customers AND Investors Reaffirming Guidance… Endnotes are included in the Appendix 2026 - 2028 Guidance On Track ► On Track for 2025 core EPS guidance (+10%) ► Reaffirming 2026 - 2028 core EPS guidance ► Targeting 20% dividend payout by 2028 ► Flat to Down 2027 bills ► 10 GW data center pipeline Key Takeaways $1.48 - $1.52 2025 Mid-Point up 10% 2024 - 2028 Equity Need Derisked At Least 9%64¢ First Half

4…Delivering For Customers AND Investors PG&E Power Pyramid… Physical and Financial Safety Decarbonized Energy System Affordable and Resilient Energy

Public 5…Benefiting Customers And Investors Layers Of Physical And Financial Protections... Physical Layers Of Protection Improving Every Year ► Real-time monitoring with automated alerts; 10,000 devices installed in highest risk areas with continued deployment planned ► 4 Black Hawk helicopters strategically positioned in high fire risk areas for rapid response ► Permanently abandoned transmission lines removed ► Expanded scope of PSPS modeling captures fuel risk beyond designated high fire threat boundaries ► Performed defensible space clearing on more than 2,000 transmission structures in the highest fire risk areas ✓ 2025 Wildfire Mitigation Plan approved with Safety Certificate issued December 2024 ✓ Independent safety regulator (OEIS) ✓ Utility conduct presumed prudent with valid annual safety certificate ✓ Enhanced cost recovery standard distinct from Wildfire Fund1 ✓ Monthly Wildfire Fund reimbursement process for 2021 Dixie Fire ✓ Customer-funded self-insurance covers claims up to Wildfire Fund’s $1 billion attachment point Financial Protections In Place Today Endnotes are included in the Appendix

6 Combined Electric and Gas Residential Bills …AND Delivers Customer Bill Stability GRC Proposal Reflects Simple, Affordable Model… 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% PLAN1 2% - 3% 2% - 4% 2% 9% - 10% 6% - 9% 1% - 3% - - OPPORTUNITY1 - ► Customer bills in 2027 are forecasted to remain flat compared to 2025 bills5 ► Headline GRC revenue requirement increase expected to be offset by non-GRC items ► Plan supports bill increases consistent with the Simple, Affordable Model (2-4%) ► DOE Loan, IG credit rating and incremental beneficial load growth could lower customer bill trajectory to 1-3% Endnotes are included in the Appendix

7…And Economic Prosperity For Customers And California Enabling Affordable Load Growth… Data Center Pipeline1 Estimated Long-Term Customer Savings2: 1 GW = 1%-2% Electric Bill Reduction MWs March 2025 June 2025 Total 8,700 10,000 Application & Preliminary Engineering 7,250 8,450 Final Engineering 1,400 1,500 Construction 50 50 Endnotes are included in the Appendix …continue to lead the AI revolution by increasing grid capacity, reliability, and efficiency…[we’re] making sure businesses get the power they need, when they need it. – Matt Mahan, San Jose Mayor

8 Non-GAAP Core EPS1 Comparison... Endnotes are included in the Appendix Second Half Factors Customer Capital Investment Operating & Maintenance Savings Redeployment 64¢ 3¢ (4¢) First Half 2025 vs. 2024 Equity Dilution 2025 First Half 2024 First Half Customer Capital Investment2 Redeployment 4¢ 69¢ Operating & Maintenance Savings Timing and Other Equity Dilution (2¢) …On Track For 2025 Guidance Of $1.48 - $1.52 Endnotes are included in the Appendix Timing and Other (6¢)

9…Stabilizing Bills AND Funding Energy System Of The Future PG&E’s 2027 General Rate Case Proposal… 20,000 Annual Customer New Connections by 2030 307 miles Annual Powerline Undergrounding 2027 Combined Residential Bills vs. 20252 Flat $2.5B Capital & Expense Enterprise Savings 2022-2024 2027 GRC By The Numbers Endnotes are included in the Appendix Residential Combined Bill Based on annual average gas and electric combined bills with constant usage. Graphic is illustrative; not to scale. GRC Base Other Bills expected flat to down in 20271 2025 2027

10 O&M Cost Reduction Performance… Examples of O&M Cost Reductions (Non-Fuel)2 Resource Management Efficiencies and Insurance Capital Conversion Planning, Execution, Automation and AI Net Cost Increases Net Savings Percent Savings $510 5½% (60)4 130 --3 350 $90 (millions) 2023 Actual $340 4% (290) 155 45 370 $60 (millions) 2024 Actual $200 2% (85) 155 45 25 $60 (millions) 2025 Plan $200 2% (140) 195 30 50 $65 (millions) LONG-TERM PLAN1 …Track Record Of Exceeding 2% Annual Reduction Target $200 - $300 2% - 3% (140) - (200) 195 - 250 30 - 100 50 $65 - $100 (millions) OPPORTUNITY1 Endnotes are included in the Appendix

11…Unchanged At $63B Five-Year Capital Plan… Plus At Least $5B Customer Beneficial Investment Opportunities3 CPUC FERC ~10% CAGR 2023-2028 % Already Authorized2 93% 93% 86% 82% Weighted Average Rate Base ($B)1 $63B 2024-2028 CPUC FERC CapEx ($B)1 Endnotes are included in the Appendix ~10% 11 11 12 13 14 15 46 52 57 61 69 76 57 63 69 74 83 91 2023A 2024A 2025F 2026F 2027F 2028F 1.5 1.9 2.1 1.8 1.9 9.1 11.0 9.9 11.8 12.1 10.6 12.9 12.0 13.6 14.0 2024A 2025F 2026F 2027F 2028F ► Transportation Electrification Capacity Investments ► Transmission Upgrades: Data Centers and System Investments ► Incremental New Business Connections ► Hydro and Storage ► IT and Automation

12…Supports Customer Capital Investment Five-Year Financing Plan… Endnotes are included in the Appendix (2½) (11) 11 3 0 10 20 30 40 50 60 70 Cash from Operations Dividends Paid Utility LT Debt Maturities Utility LT Debt Refinanced Utility LT Debt Issuance PG&E Corp. Senior Debt, Hybrid & Other Common Equity Issuance CapEx $50 $63 Amount ($billions) 2024 – 2028 Five-Year Financing Plan 14½ (2) $4 1 $12025 Utility Debt (billions)

13 SCALE RATING Moody's S&P/Fitch Moody’s S&P Fitch Investment Grade A2 A A3 A- Baa1 BBB+ Baa2 BBB Baa3 BBB- Sub- Investment Grade Ba1 BB+ Ba2 BB Ba3 BB- B1 B+ Outlook Stable Stable …Help Make Customer Investments Affordable Credit Rating Improvements1… Positive Positive SCALE DEBT RATING ’ S& / it ’s it Present 2020 Present 2020 Corporation Secured Debt Rating Utility Secured Debt Rating Endnotes are included in the Appendix

14…To Deliver For Customers Working With Policymakers And Stakeholders… 2025 10-Year Undergrounding Filing Jul 2024 GRC “Capacity Phase” Final Decision Oct 2024 Cost of Capital: Phase 2 Approval Dec 2025 2026 Cost of Capital Final Decision Aug 2024 Oakland Headquarters Approval Sept 2024 2023 WMCE Interim Rate Relief Final Decision Dec 2024 2024 Safety Certificate Issued Sept 12, 2025 California’s 2025 Legislative Session Ends May 2025 2027-2030 GRC Filing Q3 2025 Energization Revised Cost Caps Final Decision 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

15…Benefits Customers AND Investors Differentiated Performance… 2023A 2024A 2025F Future Customer Investment Rate Base Growth 14.5% 10.5% 9.5% CA Regulatory Ranking (RRA) Average/1 Average/1 Average/1 Above Average Affordable Model Non-Fuel O&M Reduction1 5½% 4% 2% 2% Load Growth2 Customer Bills3 Credit Ratings BB- /Ba2 BB /Ba1 Mid-teens FFO/Debt6 Consistent Performance Non-GAAP Core EPS Growth4 12% 11% 10% At Least 9% 2026 - 2028 Operating Cashflow $4.7B $8.0B $9B $10B+ Risk Reduction Safety Certification Valid through 12/11/25 Financial Common Dividend / Fire Victim Trust Exit Equity Issuance / Dividend Guidance 1% - 3% 2% - 4% Stronger Valuation 2 ~10%5 Investment Grade 10 Endnotes are included in the Appendix

16…And Providing Differentiated Growth For Investors Investing In California’s Prosperity… Commitment to California’s Prosperity and Growth $1.00 10% 12% 11% 10% 9% 9% 9% 21A 22A 23A 24A 25F 26F 27F 28F $B 0.8 0.9 1.4 2.0 2.9 PG&E 2023 PG&E 2024 PG&E 2028F 2024 Peer Avg 2024 Peer Top Decile Premium Growth Capital to Expense Ratio4 ~10% CAGR Rate Base Non-GAAP Core EPS2 + DPS Growth 10% 57 63 69 74 83 91 23A 24A 25F 26F 27F 28F 3 Endnotes are included in the Appendix 5-Year Capital Plan (2024-2028) invests $63B in California, supporting grid safety and reliability, while keeping affordability top of mind Critical partner to California, the world's 4th largest economy,1 delivering energy and driving economic growth and development Delivered 98% greenhouse gas-free electricity to retail customers in 2024 Collaborates with other utilities and local and state agencies to prevent, forecast, and improve response protocols for emergencies

17 Physical and Financial Safety Decarbonized Energy System Affordable and Resilient Energy Q&A

Appendix 1 Presentation Endnotes 18

19 Appendix 1: Presentation Endnotes Slide 3: Reaffirming Guidance 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. Slide 5: Layers Of Physical And Financial Protections 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. Slide 6: GRC Proposal Reflects 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 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 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. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 3. Expected drivers of forecasted electric load growth include electric vehicle adoption, data centers, 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 ; its use of self-insurance for wildfire liability insurance; 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. 5. Based on information available as of the date of this presentation, residential gas and electric bills are expected to stay f lat in 2027 compared to 2025, assuming full approval of the 2027 GRC proposal along with other reductions, such as cost recovery currently in rates expiring and subsequently being removed from rates. See “Forward Looking Statements” on slide 2. Slide 7: 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 interconnection cos ts, 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. Slide 8: Non-GAAP Core EPS Comparison 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 2. Year over year changes for customer capital investment were primarily due to the earnings impact from higher rate base, primarily offset by the change of the Utility’s authorized return on equity from 10.7% to 10.28%. Slide 9: PG&E’s 2027 General Rate Case Proposal 1. Compared to 2025 2. Based on information available as of the date of this presentation, residential gas and electric bills are expected to stay f lat in 2027 compared to 2025, assuming full approval of the 2027 GRC proposal along with other reductions, such as cost recovery currently in rates expiring and subsequently being removed from rates. See “Forward Looking Statements” on slide 2. Slide 10: O&M Cost Reduction Performance 1. These numbers are illustrative approximations and should not be interpreted as a guarantee of future performance. See “Forward-Looking Statements” on slide 2. 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. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 3. Denoted amount is not material. 4. 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. Slide titles are hyperlinks

20 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 incremental authorized spend in July 2024, Oakland headquarters Petition for Modification in August 2024 and other CPUC-jurisdictional approvals (including the full amount recoverable through a balancing account where applicable) and above-authorized capital spend that will support the Utility's plan, including strategic capital investments in electrification, energization, undergrounding, and wildfire mitigation. 2. Percentage already authorized for CPUC-jurisdictional rate base holds constant the 2026 revenue requirement for 2027 and 2028 and assumes FERC-jurisdictional rate base is equivalent to amounts requested in the formula rate through Transmission Owner rate proceedings for years 2024 through 2028. 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. Includes funds to refinance long-term debt maturing in 2026. 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. Slide 15: 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. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 2. Expected drivers of forecasted electric load growth include electric vehicle adoption, data centers, and building electrification. 3. Factors that may cause customer bills to differ from forecast include risks and uncertainties associated with energy supply costs, emergency response costs, the timing and outcomes of regulatory proceedings, and customer energy usage. 4. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 5. CAGR is from 2023 through 2028. 6. FFO/Debt is not calculated in accordance with GAAP. See Appendix 3, Exhibit E for a reconciliation of Operating income and Total debt on a GAAP basis to FFO/Debt and Appendix 3, Exhibit F regarding non-GAAP financial measures. Slide 16: 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, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 3. 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 and Appendix 9, Exhibit H regarding non-GAAP financial measures. 4. Represents Capital expenditures divided by Operating and maintenance, as disclosed in the applicable Annual Report on Form 10-K for prior periods.

21 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 23: Appendix 2: 2025 Factors Impacting Earnings 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit C for a reconciliation of EPS guidance on a GAAP basis to non-GAAP core earnings per share guidance and Appendix 3, Exhibit F 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 of the 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. 2025 equity-earning weighted-average rate base reflects 2023 GRC final decision and the April 15, 2021 FERC order denying the Utility's request for rehearing related to TO18, TO19, and TO20 formula rates. 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. 5. Refer to Appendix 3, Exhibit C: PG&E Corporation's 2025 Earnings Guidance. 6. Cash amounts for non-core items are after tax, directional, and subject to change. 7. Non-GAAP core earnings assumptions include no 2025 impacts from changes in the federal tax code. 8. 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 25: Appendix 2: Existing Construct In California Offers Sector-Leading Financial Protection 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 28: Appendix 2: SB 846 Diablo Canyon Legislation 1. The pre-extension period extends 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 22

23 2025 Factors Impacting Earnings Endnotes are included in the Appendix $1.48 - $1.52 Non-GAAP Core EPS1 Diluted Shares 20252 2,195M - 2,285M Key Ranges Weighted Average Rate Base3 CPUC $57B FERC $12B Total Rate Base $69B Equity Ratio:4 52% Return on Equity: 10.28% Non-Core Items5 Key Factors Affecting Non-GAAP Core Earnings7 ($ millions after tax) Estimated non-core items guidance $470 - $510 Non-core items cash portion6 $310 ($ millions after tax) Unrecoverable net interest8 $350 - $400 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs Changes from prior quarter noted in blue text

24 Expected Recovery Of Wildfire-Related Costs Recovery Outstanding By Year 1.1 1.4 1.6 1.6 1.6 2.6 1.1 0.4 0.2 0.9 0.8 0.1 4.6 3.3 2.1 1.8 1.6 0 1 2 3 4 5 Dec 23A Dec 24A Dec 25F Dec 26F Dec 27F Approved Pending Yet To Be Filed Total Amount ($billions) $0.4B Approved Recovery Status as of June 30, 2025 $0.6B Pending $1.6B Yet To Be Filed $2.6B Total 2023 WMCE $520M 2023 WGSC $79M

25 Existing Construct In California Offers Sector-Leading Financial Protection Protections Offered Under AB 1054 ▪ Liquidity available as soon as claims paid exceed $1B2 ▪ Wildfire Fund with at least $21B claims paying capacity ▪ CPUC empowered to authorize securitization Liquidity Available when needed ▪ Utility conduct presumed prudent ▪ Enhanced cost recovery standard distinct from Wildfire Fund ▪ Self-insurance up to $1B began in 2023 Cost Recovery Improved prudency standard1 Reimbursement Maximum liability capped ▪ If found prudent: Wildfire Fund reimbursement not required ▪ If found imprudent: reimburse Wildfire Fund ▪ Obligation is capped at 20% of electric T&D equity rate base on a 3-year rolling basis (~$4.7B)3 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 Appendix

Public 26 AB 1054 Wildfire Fund Mechanics Wildfire Fund is not reimbursed Partial or Full reimbursement (subject to 3Y rolling cap) 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 at time of disallowance

27 Revenue Requirement Proposal Benefits Customers And Builds On Safety And Reliability Progress 2027-2030 GRC Proposal ($B) 15.400 16.637 17.651 18.726 19.869 2026 Adopted 2027 Test Year 2028 2029 2030 Funding Customer Priorities CPUC Jurisdictional (GRC Only)* 2027 Test Year $67 $11.0 2028 $73 $11.0 2029 $79 $11.2 2030 $85 $11.9 * Amounts in the 2027 GRC proposal are a significant sub-set of CPUC jurisdictional rate base and CapEx as shown in PG&E’s overall Five-Year Capital Plan, which remains unchanged along with non-GAAP Core earnings per share guidance for 2025 through 2028. See page 10 of PG&E’s 2025 First Quarter Earnings presentation for the Five-Year Capital Plan. Weighted Average Rate Base CapEx Wildfire Safety • Replace 760 miles of powerlines with stronger poles and covered powerlines • Underground 307 miles of powerlines per year in highest fire-risk areas as bridge to 10Y plan • Install 114 weather stations Modern Grid • Prepare the Grid to serve new homes, businesses, 3M EVs by 2030, and AI-powered data centers • Ramp up to 20K new service customer connections per year by 2030 Gas System • Replace 164 miles of distribution pipeline and upgrade in-line inspections • Complete 600K calls to locate and mark lines • Use advanced mobile leak detection technology Clean Energy & System Resilience • Invest in lower-cost solar and battery energy storage • Install more microgrids in remote areas • Accelerate EV adoption

28 SB 846 Diablo Canyon Legislation Cost Recovery 2022-20241 2025-20302 ▪ Ongoing O&M and rate base recovery through the GRC ▪ $1.4B in state funding available to support extended operations • $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 permits NRC license renewal

29 Physical Risk Mitigation Progress Then & Now 2017 EPSS PSPS 10K UG 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 668 CAMERAS INSTALLED 1,607 STATIONS INSTALLED 24/7/365 MONITORING ASSET IMPROVEMENTS Undergrounding System Hardening Sectionalizing Devices Trees Removed 931 MILES COMPLETED * 2,199 MILES COMPLETED ** 1,782 DEVICES INSTALLED 4.1M TREES REMOVED OPERATIONAL MITIGATIONS EPSS PSPS Partial Voltage Force Out Safety and Infrastructure Protection Teams Transmission Operational Controls Downed Conductor Detection 2019 – June 30, 2025 * The 10,000-Mile Undergrounding Program started in 2021 ** System Hardening totals include data starting in 2018 2025

30 Regulatory Progress Regulatory Case/Filing Docket Status as of April 2025 Expected Milestones 2027 GRC A.25-05-009 ▪ 2027 GRC Application filed 5/15/25 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 Q3 2025 TO21 ER24-96-000 ▪ Application filed 10/13/2023 ▪ Settlement filed 3/21/25 2026 Cost of Capital A.25-03-010 ▪ Application filed 3/20/25 Final Decision Q4 2025 2021 WMCE A.21-09-008 ▪ Application filed 9/16/21 ▪ Settlement filed 1/18/23 (excludes VMBA) ▪ Final Decision on Settlement 8/31/23 ▪ VMBA Final Decision 12/27/24 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) 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 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 OEIS Draft Decision by Oct 10, 2025 2024 Safety Certificate 2024-SCs ▪ Filed 10/8/24 ▪ Safety Certificate issued by OEIS 12/11/24 Wildfire and Gas Safety Costs A.23-06-008 ▪ Filed 6/15/23 ▪ Interim rate relief granted 3/27/24 Vegetation Management Securitization A.24-06-013 ▪ Application filed 6/20/24 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

Appendix 3 Supplemental Non-GAAP Information 31

32 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 33-35 Exhibit B Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share (“EPS”) Slide 36 Exhibit C PG&E Corporation’s 2025 Earnings Guidance Slide 37-40 Exhibit D GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation Slides 41 Exhibit E 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 Slides 42 Exhibit F Non-GAAP Financial Measures Slides 43

33 Three Months Ended June 30, Six Months Ended June 30, 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 earnings/EPS on a GAAP basis $ 521 $ 520 $ 0.24 $ 0.24 $ 1,128 $ 1,252 $ 0.51 $ 0.58 Non-core items: (1) Amortization of Wildfire Fund contribution (2) 77 56 0.04 0.03 133 112 0.06 0.05 Bankruptcy and legal costs (3) 10 13 — 0.01 15 25 0.01 0.01 Investigation remedies (4) 30 15 0.01 0.01 48 19 0.02 0.01 Prior period net regulatory impact (5) (6) (6) — — (12) (12) (0.01) (0.01) SB 901 securitization (6) 3 3 — — 11 1 — — Tax-related adjustments (7) — 70 — 0.03 — 70 — 0.03 Wildfire-related costs, net of recoveries (8) 40 4 0.02 — 79 8 0.04 — PG&E Corporation’s non-GAAP core earnings/EPS (9) $ 674 $ 674 $ 0.31 $ 0.31 $ 1,402 $ 1,474 $ 0.64 $ 0.69 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. Second Quarter, 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 F: Non-GAAP Financial Measures. Exhibit A: Reconciliation of PG&E Corporation's Consolidated Earnings Available for Common Shareholders in Accordance with GAAP to Non-GAAP Core Earnings

34 Second Quarter, 2025 vs. 2024 (in millions, except per share amounts) (3) PG&E Corporation and the Utility recorded costs of $14 million (before the tax impact of $4 million) and $20 million (before the tax impact of $5 million) during the three and six months ended June 30, 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 $108 million (before the tax impact of $31 million) and $185 million (before the tax impact of $52 million) during the three and six months ended June 30, 2025, respectively, associated with the amortization of the Wildfire Fund asset, as well as 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-Q. 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 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 June 30, 2025 Six Months Ended June 30, 2025 Wildfires OII disallowance and system enhancements $ 14 $ 18 Locate and mark OII system enhancements 1 1 Paradise restoration and rebuild 1 2 2020 Zogg fire settlement 17 31 Investigation remedies $ 32 $ 53 Tax impacts (2) (5) Investigation remedies (post-tax) $ 30 $ 48 (5) The Utility recorded benefits of $8 million (before the tax impact of $2 million) and $16 million (before the tax impact of $4 million) during the three and six months ended June 30, 2025, respectively, related to adjustments 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.

35 Second Quarter, 2025 vs. 2024 (in millions, except per share amounts) (9) “Non-GAAP core earnings” is a non-GAAP financial measure. See Exhibit F: Non-GAAP Financial Measures. Undefined, capitalized terms have the meanings set forth in the Form 10-Q. (8) 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 June 30, 2025 Six Months Ended June 30, 2025 2019 Kincade fire $ 52 $ 104 2021 Dixie fire 3 7 Wildfire-related costs, net of recoveries $ 55 $ 110 Tax impacts (15) (31) Wildfire-related costs, net of recoveries (post-tax) $ 40 $ 79 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 GAAP to Non-GAAP Core Earnings (6) The Utility recorded costs of $5 million (before the tax impact of $2 million) and $15 million (before the tax impact of $4 million) during the three and six months ended June 30, 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. (7) "Tax-related adjustments” includes tax expense costs associated with the deductibility of certain customer bill credits issued in connection with the San Bruno natural gas explosion that occurred in 2010.

36 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 and six months ended June 30, 2025. Examples include reduced contract spend through contract rationalization and process improvements driven by the Lean playbook. (3) Represents redeployment of operating and maintenance savings to fund various programs including those that support risk mitigation such as inspections, gas corrosion, and distribution system maintenance during the three and six months ended June 30, 2025. (4) The earnings impact represents the dividend payment for the mandatory convertible preferred (MCP) shares 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 and six months ended June 30, 2025. (5) Represents the impact to quarterly earnings for items considered timing-related such as taxes, and other miscellaneous items such as depreciation and interest expense during the three and six months ended June 30, 2025. Second 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) $ 674 $ 0.31 $ 1,474 $ 0.69 Customer capital investment 40 0.02 80 0.04 Operating & maintenance savings (2) 48 0.02 68 0.03 Redeployment (3) (9) — (47) (0.02) Equity dilution (4) (24) (0.02) (48) (0.04) Timing and Other (5) (55) (0.02) (125) (0.06) 2025 Non-GAAP Core Earnings/EPS (1) $ 674 $ 0.31 $ 1,402 $ 0.64 Second Quarter 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")

37 2025 EPS guidance Low High Estimated EPS on a GAAP basis ~ $ 1.26 ~ $ 1.32 Estimated non-core items: (1) Amortization of Wildfire Fund contribution (2) ~ 0.11 ~ 0.11 Bankruptcy and legal costs (3) ~ 0.02 ~ 0.01 Investigation remedies (4) ~ 0.04 ~ 0.04 Prior period net regulatory impact (5) ~ (0.01) ~ (0.01) SB 901 securitization (6) ~ 0.02 ~ 0.02 Wildfire-related costs, net of recoveries (7) ~ 0.04 ~ 0.04 Estimated EPS on a non-GAAP core earnings basis ~ $ 1.48 ~ $ 1.52 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, except for certain costs that are not tax deductible. Amounts may not sum due to rounding. (1) “Non-core items” include items that management does not consider representative of ongoing earnings and affect comparability of financial results between periods. See Exhibit F: Non-GAAP Financial Measures. All adjustments related to such non-core items in the table above are presented on a diluted per-share basis. 2025 (in millions) Low guidance range High guidance range Amortization of Wildfire Fund contribution ~ $ 340 ~ $ 340 Amortization of Wildfire Fund contribution ~ $ 340 ~ $ 340 Tax impacts ~ (95) ~ (95) Amortization of Wildfire Fund contribution (post-tax) ~ $ 245 ~ $ 245 (2) “Amortization of Wildfire Fund contribution” represents the amortization of the Wildfire Fund asset, as well as 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-Q. Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 5 Earnings Guidance

38 Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance(3) “Bankruptcy and legal costs” consists of costs to resolve proof of claims filed in PG&E Corporation’s and the Utility’s Chapter 11 filing. 2025 (in millions) Low guidance range High guidance range Legal and other costs ~ $ 65 ~ $ 20 Bankruptcy and legal costs ~ $ 65 ~ $ 20 Tax impacts ~ (18) ~ (6) Bankruptcy and legal costs (post-tax) ~ $ 47 ~ $ 14 Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 5 Earnings Guidance (4) “Investigation remedies” includes the settlement agreement resolving the Safety and Enforcement Division’s investigation into the 2020 Zogg fire, the Wildfires OII decision different, and costs related to the Paradise restoration and rebuild. 2025 (in millions) Low guidance range High guidance range 2020 Zogg fire settlement ~ $ 60 ~ $ 60 Wildfires OII disallowance and system enhancements ~ 30 ~ 30 Paradise restoration and rebuild ~ 5 ~ 5 Investigation remedies ~ $ 95 ~ $ 95 Tax impacts ~ (7) ~ (7) Investigation remedies (post-tax) ~ $ 88 ~ $ 88

39 (5) “Prior period net regulatory impact” represents the recovery of capital expenditures from 2011 through 2014 above amounts adopted in the 2011 GT&S rate case. 2025 (in millions) Low guidance range High guidance range 2011-2014 GT&S capital audit ~ $ (20) ~ $ (20) Prior period net regulatory impact ~ $ (20) ~ $ (20) Tax impacts ~ 6 ~ 6 Prior period net regulatory impact (post-tax) ~ $ (14) ~ $ (14) Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 5 Earnings Guidance (6) “SB 901 securitization” includes the establishment of the SB 901 securitization regulatory asset and the SB 901 regulatory liability associated with revenue credits funded by net operating loss monetization. Also included are additional contributions to the Customer Credit Trust as a result of the decision voted out on July 24, 2025. 2025 (in millions) Low guidance range High guidance range SB 901 securitization charge ~ $ 35 ~ $ 35 Customer Credit Trust contributions ~ 25 ~ 25 SB 901 securitization ~ $ 60 ~ $ 60 Tax impacts ~ (17) ~ (17) SB 901 securitization (post-tax) ~ $ 43 ~ $ 43

40 Undefined, capitalized terms have the meanings set forth in the Form 10-Q. (7) “Wildfire-related costs, net of recoveries” includes costs to resolve third-party claims, net of recoveries, for the 2019 Kincade fire and 2021 Dixie fire, inclusive of outside counsel fees. 2025 (in millions) Low guidance range High guidance range 2019 Kincade fire ~ $ 107 ~ $ 107 2021 Dixie fire ~ 18 ~ 18 Wildfire-related costs, net of recoveries ~ $ 125 ~ $ 125 Tax impacts ~ (35) ~ (35) Wildfire-related costs, net of recoveries (post-tax) ~ $ 90 ~ $ 90 Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 5 Earnings Guidance

41 Three Months Ended June 30, Six Months Ended June 30, (in millions) 2025 2024 2025 2024 PG&E Corporation’s Net Income on a GAAP basis $ 549 $ 524 $ 1,183 $ 1,259 Income tax provision (benefit) 20 82 59 121 Other income, net (84) (82) (154) (158) Interest expense 792 812 1,526 1,527 Interest income (181) (202) (298) (339) Operating Income $ 1,096 $ 1,134 $ 2,316 $ 2,410 Depreciation, amortization, and decommissioning 1,073 1,053 2,170 2,075 Amortization of Wildfire Fund contribution 109 78 185 156 SB 901 securitization 5 4 15 1 Investigation remedies 32 16 53 20 Prior period net regulatory impact (8) (8) (16) (16) Wildfire-related costs, net of recoveries 55 6 110 11 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 2,362 $ 2,283 $ 4,833 $ 4,657 Second Quarter, 2025 vs. 2024 Amounts may not sum due to rounding. “Non-GAAP Adjusted EBITDA” is a non-GAAP financial measure. Exhibit D: GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation PG&E CorporationExhibit D: GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation

42 Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit E: 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 2024 (in millions) Operating income $ 4,459 Depreciation, amortization, and decommissioning 4,189 SB 901 securitization charges, net 33 Wildfire-related claims, net of recoveries 94 Adjustments: Cash interest (1) (2,421) ARO accretion 269 Operating lease fixed cost 116 Other (22) Adjusted FFO $ 6,717 2024 (in millions) Long-term debt $ 53,569 Long-term debt, classified as current 2,146 Short-term borrowings 1,523 Adjustments: Cash and cash equivalents (940) Securitized debt (10,367) Junior subordinated notes (750) Power purchase commitments debt equivalents 1,393 ARO debt 1,273 Operating lease liabilities 524 Financing lease liabilities 581 Noncontrolling Interest - Preferred Stock of Subsidiary 126 Adjusted Total Debt $ 49,077 Adjusted FFO Calculation Adjusted Total Debt Calculation Adjusted FFO = $6,717 = 13.7% Adjusted Total Debt $49,077 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

43 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 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 a measure that allows 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. With respect to our projection of non-GAAP core EPS for the years 2026-2028, PG&E Corporation is unable to predict with reasonable certainty the reconciling items that may affect GAAP net income without unreasonable effort. The reconciling items are primarily due to the future impact of wildfire-related costs, timing of regulatory recoveries, special tax items, and investigation remedies. These reconciling items are uncertain, depend on various factors and could significantly impact, either individually or in the aggregate, the GAAP measures. 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 F: Non-GAAP Financial Measures Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance