EX-99.2 3 q324earningspresentation.htm EX-99.2
2024 THIRD QUARTER EARNINGS November 7, 2024 Delivering For Customers AND Investors 1

2 This presentation contains 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 2024 and 2025 non-GAAP core earnings), debt and equity issuances, rate base growth, capital expenditures, cash flow, cost savings, customer bills, wildfire risk mitigation, future dividends, 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, the undergrounding initiative, 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 wildfires, the environment, California’s clean energy goals, the nuclear industry, extended operations at Diablo Canyon nuclear power plant, regulation of utilities’ transactions with their affiliates, municipalization, privacy, 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; 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, 2023, their joint Quarterly Report on Form 10-Q for the quarter ended September 30, 2024 (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 November 7, 2024. 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 November 7, 2024, and is also available on PG&E Corporation’s website at www.pgecorp.com. Forward-Looking Statements

3 Non-GAAP Core EPS1 37¢ Third Quarter 2024 Results …For Customers AND Investors Strengthening Guidance… Endnotes are included in the Appendix $1.34 - $1.372024 At Least 9%2026-2028 Equity 2024: None ’25-’28: $3B Updated Guidance ON TRACK ► Raising 2024 guidance low end ► Delivering on physical and financial safety ► Executing on the PG&E Performance Playbook ► Adding $1B to 5Y CapEx for Growing Customer Demand ► Approved by CPUC ► Prefinanced with $1B Junior Subordinated Notes ► Increasing 5Y rate base CAGR to ~10% ► Raising 2025 Core EPS growth to 10% Key Takeaways $1.06 Year To Date $1.47 - $1.51 2025 Up 10% CapEx $1B 2024-2028 Up 10%

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

5…Making Our System Safer Every Day Physical Risk Mitigations... Endnotes are included in the Appendix Moody’s Assessment Estimate of Wildfire Risk Reduction Economic Loss1 93% HFTD + HFRA Weather-Normalized Ignition Rates R3+ per 100k Circuit Mile Days 2024 shows 365-day rolling as of 11/4/24 Weather-Normalized Ignition Rate 186 150 132 564 1,335 78 0 0 2021 2022 2023 2024 YTD Incidents ≥ 10 Acres in California * (all sources) Structures Destroyed in PG&E Reportable Fires in HFTD/HFRA During R3+ Conditions Riskier California Wildfire Season… …Layers of Protection Delivered 3.23 2.67 2.25 2.76 1.93 0.95 0.93 1.44 2017 2018 2019 2020 2021 2022 2023 2024 * As Reported By CAL FIRE EPSS Implemented Mid-2021

6 AB 1054 In California… Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance Protections Offered Under AB 1054 …Offers Sector-Leading Financial Protection ▪ Liquidity available as soon as claims paid exceed $1B2 ▪ Wildfire Fund with $21B claims paying capacity (sized to last 20 years) ▪ Received 2nd monthly reimbursement for 2021 Dixie Fire Liquidity Available when needed ▪ Utility conduct presumed prudent ▪ Can apply for recovery of claims above insurance but below $1B ▪ Self-insurance 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 (~$4.1B)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

7 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 Our Simple, Affordable Model… 2% 1% - 3% 2% ~9% 5% - 7% 2% - 4% PLAN1 …Strong Existing Plan, Being Amplified 2% - 3% 2% - 4% 2% 9% - 10% 6% - 9% 1% - 3% - - OPPORTUNITY1 Endnotes are included in the Appendix

8Performance Playbook Delivering For Customers Story Of The Month: PG&E’s Dublin Innovation Center Utilizing the Performance Playbook to Rapidly Implement Regulatory Approvals The CPUC approved $1B of energization funding incremental to our workplan. Utilizing Lean, PG&E found over 3,000 additional customer requests that could be completed in 2024.

9 Non-GAAP Core EPS1 Comparison... Endnotes are included in the Appendix Fourth Quarter Factors Customer Capital Investments Operating & Maintenance Savings Redeployment 11¢ 76¢ $1.06 4¢ (7¢) 2¢ First Nine Months Operating & Maintenance Savings 2024 First Nine Months 2023 First Nine Months Customer Capital Investment Redeployment 20¢ GRC Benefit2 As Reported 87¢ Timing and Other …On Track for Narrowed 2024 Guidance $1.34-$1.37 Endnotes are included in the Appendix

10…Raised To $63B Five-Year Capital Plan… Plus At Least Customer Beneficial Investment Opportunities3 Transportation Electrification Capacity Investments Transmission Upgrades: Data Centers and System Investments Incremental New Business Connections Hydro and Storage IT and Automation $5B CPUC FERC ~10% CAGR 2023-2028 % Already Authorized1 93% 93% 86% 82%94% Weighted Average Rate Base ($B) $63B 2024-2028 CPUC FERC CapEx ($B)2 Endnotes are included in the Appendix $63 11 11 12 13 14 15 46 52 57 61 69 76 57 63 69 74 83 91 2023A 2024F 2025F 2026F 2027F 2028F 1.4 1.5 2.1 1.8 1.8 1.9 8.4 9.3 10.7 10.2 11.8 12.1 9.8 10.8 12.8 12.0 13.6 14.0 2023A 2024F 2025F 2026F 2027F 2028F

11…Supports Increased Customer Capital Investment Five-Year Financing Plan… (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) +½ +½ +$1 COMPARED TO Q2 CALL COMPARED TO Q2 Junior Sub. Notes: + 1 Corp. Term Loan B: - ½

12 O&M Cost Reduction Performance… Examples of O&M Cost Reductions (Non-Fuel) Resource Management Efficiencies and Insurance Capital Conversion Planning, Execution and Automation Net Cost Increases Net Savings Percent Savings $330 3% (115) 50 100 270 $25 (millions) 2022 Actual $510 5½% (60)2 130 --1 350 $90 (millions) 2023 Actual $200 2% (200) 155 30 150 $65 (millions) 2024 Plan $200 2% (140) 195 30 50 $65 (millions) LONG-TERM PLAN3 …On Track For At Least 2% Annual Reduction Target $200 - $300 2% - 3% (140) - (200) 195 - 250 30 - 100 50 $65 - $100 (millions) OPPORTUNITY3 - Endnotes are included in the Appendix

13 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 Our Simple, Affordable Model… 2% 1% - 3% 2% ~9% 5% - 7% 2% - 4% PLAN1 …Strong Existing Plan, Being Amplified 2% - 3% 2% - 4% 2% 9% - 10% 6% - 9% 1% - 3% - - OPPORTUNITY1 Endnotes are included in the Appendix

14 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- Outlook Stable …Helps Make Customer Investments Affordable Credit Rating Improvements1… Positive Positive SCALE RATING ’ S& / it ’s it Present 2020 Present 2020 Issuer Credit Rating2 Utility Secured Rating Endnotes are included in the Appendix

15…Underpins Mid-Teens FFO/Debt1 Operating Cash Flow Growth… $Billions $3.7 $4.7 $8.3 $2.7 $4.3 $6.1 $0 $2 $4 $6 $8 $10 2022A 2023A 2024F As of Dec. 31 As of Sep. 30 Operating Cash Flow Growth On Track 2023 GRC Catch-Up 2024 GRC Revenue 2022 WMCE Interim Rate Relief 2023 WGSC Interim Rate Relief 2023 Energy Cost Recovery Catch-Up +$1.8B +$3.6B Endnotes are included in the Appendix

16…To Execute Our Plan Working With Policymakers And Stakeholders… Jan 2023 Wildfire Self-Insurance Settlement Q4 2024 OEIS 10-Year Undergrounding Guidelines to be Finalized May 2023 Safety Culture Proceeding Resolved Financial Risk Mitigation – complete Physical Risk Mitigation – complete Physical Risk Mitigation – planned Jun 2023 2022 WMCE Interim Rate Relief Final Decision Oct 2023 SB 410 Signed Diablo Canyon NRC Filing Nov 2023 2023 GRC Final Decision Dec 2023 Cost of Capital AL Approval Dec 2023 2023 WMP Final Decision Jan 2024 2023 Safety Certificate Issued Mar 2024 2023 WGSC Interim Rate Relief Final Decision May 2024 Climate Adaptation Vulnerability Assessment Jul 2024 GRC “Capacity Phase” Final Decision Oct 2024 Cost of Capital: Phase 2 Approval Q1 2025 Energization Revised Cost Caps Proposed Decision Aug 2024 Oakland Headquarters Approval Sept 2024 2023 WMCE Interim Rate Relief Final Decision Financial Risk Mitigation – planned Jan 2025 2024 Safety Certificate

17…Benefits Customers AND Investors Differentiated Performance… Endnotes are included in the Appendix 2022A 2023A 2024F Future Customer Investment Rate Base Growth 5.5% 14.5% 10.5% CA Regulatory Ranking (RRA) Average/2 Average/1 Above Average Affordable Model Non-Fuel O&M Reduction1 3% 2% Load Growth2 Bills3 Credit Ratings BB-/Ba2 BB- /Ba2 BB/Ba1 Consistent Performance Non-GAAP Core EPS Growth4 10% 12% 10% Operating Cashflow $3.7B $4.7B $8.3B $10B+ Risk Reduction Safety Certification Valid through 1/22/25 Financial S&P 500 / Rate Neutral Securitization Common Dividend / Fire Victim Trust Exit 1% - 3% 2% - 4% Investment Grade & Mid-teens FFO/Debt6 Premium Multiple 5½% 2% ~10%5 At Least 10% 2025 At Least 9% 2026 - 2028

18…Building Trust With Customers AND Investors Differentiated Growth And Regulatory Visibility… $1.00 2 10% 10% 9% 9% 9% 21A 22A 23A 24F 25F 26F 27F 28F $B 2023 2025 2030 2035 2040 73 77 87 108 144 PG&E Load Growth Opportunity (TWh) CAGR Electric Vehicles 1.25% - 2% Data Centers 0.5% - 1.5% Building Electrification 0.25% - 0.5% Total Load (TWh) 2% - 4% 2023 - 2040 Diversified Contributors to Load Growth 0.8 1.4 1.6 2.4 PG&E 2023 PG&E 2028F 2023 Peer Avg 2023 Peer Top Decile Premium Growth Capital to Expense Ratio4 Load Growth Opportunity3 ~10% CAGR 4-Year Revenue Certainty 3-Year CoC Cycle w/ ROE Adjustment Mechanism GRC Phase 2 Energization Approval Constructive Legislation SB 884, SB 846, SB 410 CA Carbon Neutrality by 2045 Regulatory and Policy Environment Endnotes are included in the Appendix 57 63 69 74 83 91 23A 24F 25F 26F 27F 28F Rate Base Core EPS1 + DPS Growth 10% 12% 10%

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

Appendix 1 Presentation Endnotes 20

21 Appendix 1: Presentation Endnotes Slide 3: Strengthening 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 E regarding non-GAAP financial measures. Slide 5: Physical Risk Mitigations 1. Refers to the reduction in the value of the economic loss from direct third-party private property damage and ensuing business interruption that has a 20% probability of being exceeded in any given year, comparing forecast estimates with and without physical mitigations, PSPS, and EPSS. Wildfire risk reduction economic losses estimated by Moody’s using the Moody’s RMS wildfire model assume current climate conditions continue and rely on data and assumptions about fires prevented by existing mitigations provided by PG&E Corporation and the Utility. There are risks inherent in the simulation analysis, models, and predictions of PG&E Corporation, the Utility, and Moody’s relating to the likelihood of and damage due to wildfires and climate change. As with any simulation analysis or model related to physical systems, particularly those with lower frequencies of occurrence and potentially high severity outcomes, the actual losses from catastrophic wildfire events may differ from the results of the simulation analysis and models of Moody’s, PG&E Corporation, and the Utility. Slide 6: AB 1054 In California 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 2024 electric transmission and distribution equity rate base. Slide 7: Our 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. 2% reduction calculated based on the prior year’s operating and maintenance costs, excluding non-core items; balancing account deferrals; property taxes; write-offs for canceled work including the Pacific Generation transaction; 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. 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. Slide 9: 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 E regarding non-GAAP financial measures. 2. GRC benefit represents the return on equity on the incremental increase to the Utility’s weighted-average rate base that would have been attributable to the first nine months of 2023 if the Utility had received a final decision in the 2023 General Rate Case in the first quarter of 2023. The inclusion of the GRC benefit on this slide is illustrative in nature and does not reflect non-GAAP core EPS results reported for the first nine months of 2023. See Appendix 3, Exhibit B for a breakdown of the key drivers of PG&E Corporation’s non-GAAP core EPS, which includes an adjustment for the GRC benefit in the calculation of non-GAAP core EPS for the first nine months of 2024. Slide 10: Five-Year Capital Plan 1. 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. 2. 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. 3. Investment opportunities of at least $5 billion are not reflected in the CapEx or rate base numbers. Slide 12: O&M Cost Reduction Performance 1. Denoted amount is not material. 2. 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. 3. These numbers are illustrative approximations and should not be interpreted as a guarantee of future performance. Slide titles are hyperlinks

22 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 13: Our 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. 2% reduction calculated based on the prior year’s operating and maintenance costs, excluding non-core items; balancing account deferrals; property taxes; write-offs for canceled work including the Pacific Generation transaction; 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. 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. Slide 14: 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. Issuer credit rating is the same for each of PG&E Corporation and the Utility. Slide 15: Operating Cash Flow Growth 1. FFO/Debt is not calculated in accordance with GAAP. Because PG&E Corporation is not able to estimate the impact of specific l ine items, which have the potential to significantly impact the company’s FFO/Debt in future periods, it is not providing a reconciliation for future period FFO/Debt. Slide 17: 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. 2% reduction calculated based on the prior year’s operating and maintenance costs, excluding non-core items; balancing account deferrals; property taxes; write-offs for canceled work and the aborted Pacific Generation transaction; 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. 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 E regarding non-GAAP financial measures. 5. CAGR is from 2023 through 2028. 6. FFO/Debt is not calculated in accordance with GAAP. Because PG&E Corporation is not able to estimate the impact of specific l ine items, which have the potential to significantly impact the company’s FFO/Debt in future periods, it is not providing a reconciliation for future period FFO/Debt. Slide 18: Differentiated Growth And Regulatory Visibility 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 E regarding non-GAAP financial measures. 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 and Appendix 9, Exhibit H regarding non-GAAP financial measures. 3. Factors that may cause the Utility’s actual results to differ materially from its forecasts include: 1) Electric vehicles: the availability of charging infrastructure, supply chain issues, government regulations and economic incentives, the costs of gasoline and electricity, and the degree to which state purchase mandates result in consumers converting to EVs; 2) Data centers: the cost of electricity, the extent of demand for local data center systems and products, power supply and grid capacity, whether customers follow through with data center requests, customer on-site generation, supply chain issues, technological developments, and government regulations and permitting; and 3) Building electrification: the Utility’s ability to meet customer demand for new business interconnections and grid upgrades in a timely manner, customer preferences, supply chain issues, and government regulation and economic incentives, including the success of litigation challenging public policies. 4. Represents Capital expenditures divided by Operating and maintenance, as disclosed in the applicable Annual Report on Form 10-K.

23 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 25: Appendix 2: 2024 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 and Appendix 3, Exhibit E regarding non-GAAP financial measures. 2. 2024 equity earning 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. 3. 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. 4. Refer to Appendix 3, Exhibit C: PG&E Corporation's 2024 and 2025 Earnings Guidance. 5. Cash amounts for non-core items are after tax, directional, and subject to change. 6. Non-GAAP core earnings assumptions include no 2024 impacts from changes in the federal tax code. 7. 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 26: 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 and Appendix 3, Exhibit E regarding non-GAAP financial measures. 2. 2025 equity earning 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. 3. 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. 4. Refer to Appendix 3, Exhibit C: PG&E Corporation's 2024 and 2025 Earnings Guidance. 5. Cash amounts for non-core items are after tax, directional, and subject to change. 6. Non-GAAP core earnings assumptions include no 2025 impacts from changes in the federal tax code. 7. 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 28: New Load In PG&E’s Service Area Helps with Customer Affordability 1. Factors that may cause the Utility’s actual results to differ materially from its forecasts include the Utility's interconnec tion costs, the amount of power used by customers, the price of power, the amount of cost recovery approved in the Utility's ratemaking proceedings, and with respect to data centers, the extent to which power supply costs are passed through to other customers. 2. Represents incremental new electric vehicles after June 2024; subsequent new load likely will have increased system capital needs. Slide 29: 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. Slide 33: Appendix 2: California Wildfire Risk Framework 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. Cap does not apply if the Utility is found to have acted with conscious or willful disregard of the rights and safety of others. 3. Refers to the reduction in the value of the economic loss from direct third-party private property damage and ensuing business interruption that has a 20% probability of being exceeded in any given year, comparing forecast estimates with and without physical mitigations, PSPS, and EPSS. Wildfire risk reduction economic losses estimated by Moody’s using the Moody’s RMS wildfire model assume current climate conditions continue and rely on data and assumptions about fires prevented by existing mitigations provided by PG&E Corporation and the Utility. There are risks inherent in the simulation analysis, models, and predictions of PG&E Corporation, the Utility, and Moody’s relating to the likelihood of and damage due to wildfires and climate change. As with any simulation analysis or model related to physical systems, particularly those with lower frequencies of occurrence and potentially high severity outcomes, the actual losses from catastrophic wildfire events may differ from the results of the simulation analysis and models of Moody’s, PG&E Corporation, and the Utility.

Appendix 2 Supplemental Earnings Materials 24

25 2024 Factors Impacting Earnings Endnotes are included in the Appendix Changes from prior quarter noted in blue text $1.34 - $1.37 Non-GAAP Core EPS1 New Equity in 2024 $0 Key Ranges Weighted Average Rate Base2 CPUC $52B FERC $11B Total Rate Base $63B Equity Ratio:3 52% Return on Equity: 10.7% Non-Core Items4 Key Factors Affecting Non-GAAP Core Earnings6 ($ millions after tax) Estimated non-core items guidance $510 - $550 Non-core items cash portion5 $270 ($ millions after tax) Unrecoverable net interest7 $285 - $365 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs

26 2025 Factors Impacting Earnings Endnotes are included in the Appendix $1.47 - $1.51 Non-GAAP Core EPS1 New Equity 2025 - 2028 $3B Key Ranges Weighted Average Rate Base2 CPUC $57B FERC $12B Total Rate Base $69B Equity Ratio:3 52% Return on Equity: 10.28% Non-Core Items4 Key Factors Affecting Non-GAAP Core Earnings6 ($ millions after tax) Estimated non-core items guidance $340 - $380 Non-core items cash portion5 $300 ($ millions after tax) Unrecoverable net interest7 $350 - $400 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs

27 Expected Recovery Of Wildfire-Related Costs Recovery Outstanding By Year 1.1 1.4 1.4 1.4 2.6 1.8 1.1 1.1 0.9 0.3 4.6 3.5 2.5 2.5 0 1 2 3 4 5 Dec 23A Dec 24F Dec 25F Dec 26F Approved Pending Yet To Be Filed Total Amount ($billions) $0.5B Approved Recovery Status as of September 30, 2024 $2.0B Pending $1.4B Yet To Be Filed $3.8B Total 2021 WMCE $607M 2022 WMCE $59M 2023 WMCE $1,041M 2023 WGSC $254M

28 Data Centers New Load In PG&E’s Service Area…New Load In PG&E’s Service Area Helps With Customer Affordability Net Customer Benefit (Annual) Net Monthly Bill Savings (Electric) $200M - $350M System Capital Need $0.5B - $1.6B Incremental Load 1,000 MW Less: Cost of Required System Upgrades ($100M - $250M) New T&D Revenue from Incremental Load $450M Beneficial Load Modeling Guidelines1 1% - 2% Capital Needs Customer Savings New Load Electric Vehicles $500M - $550M $1.5B - $2.0B 1M EVs2 ($250M - $300M) $800M 2% - 3% Endnotes are included in the Appendix

29 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

30 Wildfire Mitigation Plan Progress Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance Undergrounding Our Lines Undergrounding powerlines to reduce wildfires caused by equipment System Hardening Strengthening our grid by installing stronger poles, covered powerlines and undergrounding Sectionalizing Devices and Transmission Switches Separating the grid into smaller sections and narrowing the scope of Public Safety Power Shutoffs High-Definition Cameras Monitoring and responding to wildfires through increased visibility Weather Stations Better predicting and responding to severe weather threats 7 48 120 300 664 2019 2020 2021 2022 2023 2024 914 188 530 741 1,224 1,671 2019 2020 2021 2022 2023 2024 1,951 241 899 1,209 1,351 1,427 2019 2020 2021 2022 2023 133 349 502 602 602 2019 2020 2021 2022 2023 627 1,005 1,313 1,424 1,424 2019 2020 2021 2022 2023 2019-2023 ACTUALS STATIONS INSTALLED 1,424 CAMERAS INSTALLED 602 DEVICES INSTALLED 1,427 LINE MILES HARDENED 1,671 MILES COMPLETED 664 2024 TARGET MILES 250 LINE MILES 280 PROGRAM COMPLETED PROGRAM COMPLETED PROGRAM COMPLETED Completed Target

31 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 630 CAMERAS INSTALLED 1,577 STATIONS INSTALLED 24/7/365 MONITORING ASSET IMPROVEMENTS Undergrounding System Hardening Sectionalizing Devices Trees Removed 737 MILES COMPLETED * 1,877 MILES COMPLETED ** 1,492 DEVICES INSTALLED 3.6M TREES REMOVED OPERATIONAL MITIGATIONS EPSS PSPS Partial Voltage Force Out Safety and Infrastructure Protection Teams Transmission Operational Controls Downed Conductor Detection 2019 - September 30, 2024 * The 10,000-Mile Undergrounding Program started in 2021 ** System Hardening totals include data starting in 2018 2024

32 PG&E Utility Securitization Program Changes from prior quarter noted in blue text The Utility has completed $10.7B of securitization issuances Rate Neutral Securitization A.20-04-023 ▪ SB 901 signed into law on September 21, 2018Statutory Authority: ▪ AB 1054 signed into law on July 12, 2019 ▪ Up to $7.5B in up to three issuances by December 31, 2022Total Issuance Amount: ▪ Up to $3.2B across several bond issuances ▪ Pay or reimburse the Utility for incurred costs and expenses relating to catastrophic wildfires ignited in 2017 Use of Proceeds: ▪ Reimburse capital expenses associated with wildfire risk mitigation ▪ Financing order issued on May 11, 2021 ▪ Financing order became final, non-appealable February 28, 2022 Financing Order: ▪ First financing order became final, non-appealable July 6, 2021 ▪ Second financing order became final, non-appealable August 15, 2022 ▪ Third financing order became final, non-appealable February 26, 2024 ▪ Issuances complete ▪ $3.6B issued in May 2022 ▪ $3.9B issued in July 2022 Securitization Timing: ▪ $860M recovery bonds issued in November 2021 ▪ $983M recovery bonds issued in November 2022 ▪ $1.4B recovery bonds issued in August 2024 AB 1054 CapEx Securitization A.22-03-010Complete Complete

33 California Wildfire Risk Framework AB 1054 Provides Liquidity, Cost Recovery, and Capped Liability • Wildfire Fund offers liquidity for claims >$1B • Upfront presumption of prudency with annual safety certification and enhanced prudency standard1 • Shareholder liability capped if imprudent2 Constructive Stakeholder Engagement • WMP review by safety regulator (OEIS) and CPUC • Open-source partnership with industry innovators to further reduce risk • SB 884 provides for utilities to propose 10-year undergrounding plans • State provides $2.3B for wildfire and forest resilience 2021 through 2025 PG&E Self-Insurance Limits Exposure • Since 2023, claims up to $1B are covered by the Utility’s customer-funded self-insurance program • Limits financial exposure to $50M deductible • Significant savings for customers versus commercial insurance Proven Mitigations Reducing Wildfire Risk • Annual Wildfire Mitigation Plan (WMP) sets clear regulatory and operational expectations • Layers of Protection: EPSS, PSPS, enhanced situational awareness, and suppression resources • Moody’s Assessment Estimate of Wildfire Risk Reduction Economic Loss: 93%3 93%3 Endnotes are included in the Appendix

34 Regulatory Progress Regulatory Case/Filing Docket Status as of November 2024 Expected Milestones 2023 GRC A.21-06-021 ▪ 2023 GRC Application filed 6/30/21 ▪ Wildfire Self-Insurance Final Decision received 1/12/23 ▪ Final Decision received 11/16/23 ▪ “Capacity Phase” Final Decision received 7/11/24 2025 and 2026 Energization Cost Caps R.24-01-018 ▪ Motion to revise 2025 and 2026 Energization Cost Caps filed 10/4/24 TO21 ER24-96-000 ▪ Application filed 10/13/2023 2023 Cost of Capital A.22-04-008 ▪ 2023 Application filed 4/20/22 ▪ Final Decision 12/15/22 ▪ Phase 2 Briefing Completed 5/31/2024 ▪ ACCAM Tier 2 Advice Letter approved 12/22/23 (4813-G/7046-E) and Resolution E-5306 approved 7/11/24 ▪ Phase 2 Final Decision received 10/17/24 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 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 Final Decision Q2 2025 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 ▪ Draft Decision received 8/29/24 Final Decision on 2025 Update 2024 Safety Certificate 2024-SCs ▪ Filed 10/8/24 No later than 90 days after submission Wildfire and Gas Safety Costs A.23-06-008 ▪ Filed 6/15/23 ▪ Interim rate relief granted 3/27/24 Track 1 Proposed Decision Q1/Q2 2025 Vegetation Management Securitization A.24-06-013 ▪ Application filed 6/20/24 Changes from prior quarter noted in blue text

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 Generally Accepted Accounting Principles (“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 PG&E Corporation’s 2024 and 2025 Earnings Guidance Slides 42-45 Exhibit D GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation Slides 46 Exhibit E Non-GAAP Financial Measures Slides 47

37 Three Months Ended September 30, Nine Months Ended September 30, Earnings Earnings per Common Share Earnings Earnings per Common Share (in millions, except per share amounts) 2024 2023 2024 2023 2024 2023 2024 2023 PG&E Corporation’s earnings/EPS on a GAAP basis $ 576 $ 348 $ 0.27 $ 0.16 $ 1,828 $ 1,323 $ 0.85 $ 0.62 Non-core items: (1) Amortization of Wildfire Fund contribution (2) 100 157 0.05 0.07 212 326 0.10 0.15 Bankruptcy and legal costs (3) 9 47 — 0.02 34 81 0.02 0.04 Fire Victim Trust tax benefit net of securitization (4) 31 (46) 0.01 (0.02) 31 (185) 0.01 (0.09) Investigation remedies (5) 21 3 0.01 — 41 20 0.02 0.01 Prior period net regulatory impact (6) (6) (6) — — (17) (17) (0.01) (0.01) Strategic repositioning costs (7) — 1 — — — 3 — — Tax-related adjustments (8) — — — — 70 — 0.03 — Wildfire-related costs, net of recoveries (9) 60 9 0.03 — 66 73 0.03 0.03 PG&E Corporation’s non-GAAP core earnings/EPS (10) $ 791 $ 513 $ 0.37 $ 0.24 $ 2,265 $ 1,624 $ 1.06 $ 0.76 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 2024 and 2023, except for certain costs that are not tax deductible. Amounts may not sum due to rounding. Third Quarter, 2024 vs. 2023 (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 Third Quarter, 2024 vs. 2023 (in millions, except per share amounts) (3) PG&E Corporation and the Utility recorded costs of $12 million (before the tax impact of $3 million) and $47 million (before the tax impact of $13 million) during the three and nine months ended September 30, 2024, respectively, related to bankruptcy and legal costs associated with PG&E Corporation’s and the Utility’s Chapter 11 filing, including legal and other costs. (2) The Utility recorded costs of $139 million (before the tax impact of $39 million) and $295 million (before the tax impact of $83 million) during the three and nine months ended September 30, 2024, respectively, associated with the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability. 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) The Utility recorded costs of $42 million (before the tax impact of $11 million) and $43 million (before the tax impact of $12 million) during the three and nine months ended September 30, 2024, respectively, related to any earnings-impacting investment losses or gains associated with investments related to the contributions to the customer credit trust, as well as the charge related to 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. 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

39 Third Quarter, 2024 vs. 2023 (in millions, except per share amounts) (in millions) Three Months Ended September 30, 2024 Nine Months Ended September 30, 2024 Wildfires OII disallowance and system enhancements $ 1 $ 5 Locate and mark OII system enhancements 1 2 Paradise restoration and rebuild 2 4 2020 Zogg fire settlement 20 34 Investigation remedies $ 24 $ 45 Tax impacts (3) (4) Investigation remedies (post-tax) $ 21 $ 41 (5) Includes costs associated with the decision different for the 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. 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 $8 million (before the tax impact of $2 million) and $24 million (before the tax impact of $7 million) during the three and nine months ended September 30, 2024, 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. 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 (7) Includes one-time costs related to repositioning PG&E Corporation’s and the Utility’s operating model.

40 Third Quarter, 2024 vs. 2023 (in millions, except per share amounts) (10) “Non-GAAP core earnings” is a non-GAAP financial measure. See Exhibit E: Non-GAAP Financial Measures. Undefined, capitalized terms have the meanings set forth in PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q for the quarter ended September 30, 2024. (9) Includes costs associated with the 2019 Kincade fire, 2020 Zogg fire, and 2021 Dixie fire, net of recoveries, as shown below. (in millions) Three Months Ended September 30, 2024 Nine Months Ended September 30, 2024 2019 Kincade fire-related third-party claims $ 75 $ 75 2019 Kincade fire-related costs 2 6 2020 Zogg fire-related insurance recoveries — (1) 2020 Zogg fire-related legal settlements — — 2021 Dixie fire-related legal settlements 5 12 Wildfire-related costs, net of recoveries $ 82 $ 92 Tax impacts (22) (26) Wildfire-related costs, net of recoveries (post-tax) $ 60 $ 66 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) PG&E Corporation recorded tax expense costs of $70 million during the nine months ended September 30, 2024 associated with the deductibility of 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 2024 and 2023. 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 the return on equity on the incremental increase to the Utility’s weighted-average rate base that would have been attributable to the three and nine months ended September 2023 if the Utility had received a final decision in the 2023 General Rate Case in the first quarter of 2023. (3) Represents operating and maintenance savings for various initiatives, during the three and nine months ended September 30, 2024. Examples include reduced contract spend through contract rationalization and process improvements for inspections. (4) Represents redeployment of operating and maintenance savings to fund various programs that support risk mitigation for inspections and corrosion maintenance, during the three and nine months ended September 30, 2024. (5) Represents the timing of taxes reportable in quarterly statements in accordance with Accounting Standards Codification 740, Income Taxes, and results from variances in the percentage of quarterly earnings to annual earnings, timing of overheads, administrative and general costs allocated to capital projects, and timing of nuclear outages during the three and nine months ended September 30, 2024. Third Quarter 2024 vs. 2023 Year to Date 2024 vs. 2023 Earnings Earnings per Common Share Earnings Earnings per Common Share 2023 Non-GAAP Core Earnings/EPS (1) $ 513 $ 0.24 $ 1,624 $ 0.76 2023 GRC benefit (2) 72 0.04 206 0.11 Customer capital investment 137 0.07 411 0.20 Operating and maintenance savings (3) 29 0.01 81 0.04 Redeployment (4) (54) (0.02) (136) (0.07) Timing and other (5) 94 0.03 79 0.02 2024 Non-GAAP Core Earnings/EPS (1) $ 791 $ 0.37 $ 2,265 $ 1.06 Third Quarter, 2024 vs. 2023 (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 2024 2025 EPS guidance Low High Low High Estimated EPS on a GAAP basis ~ $ 1.09 ~ $ 1.14 ~ $ 1.30 ~ $ 1.36 Estimated non-core items: (1) Amortization of Wildfire Fund contribution (2) ~ 0.13 ~ 0.13 ~ 0.10 ~ 0.10 Bankruptcy and legal costs (3) ~ 0.03 ~ 0.01 ~ 0.02 ~ 0.01 SB 901 securitization (4) ~ 0.01 ~ 0.01 ~ 0.01 ~ 0.01 Investigation remedies (5) ~ 0.03 ~ 0.03 ~ 0.03 ~ 0.03 Prior period net regulatory impact (6) ~ (0.01) ~ (0.01) ~ (0.01) ~ (0.01) Tax-related adjustments (7) ~ 0.03 ~ 0.03 ~ — ~ — Wildfire-related costs, net of recoveries (8) ~ 0.03 ~ 0.03 ~ 0.01 ~ 0.01 Estimated EPS on a non-GAAP core earnings basis ~ $ 1.34 ~ $ 1.37 ~ $ 1.47 ~ $ 1.51 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 2024 and 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 E: Non-GAAP Financial Measures. 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range Amortization of Wildfire Fund contribution ~ $ 375 ~ $ 375 ~ $ 310 ~ $ 310 Amortization of Wildfire Fund contribution ~ $ 375 ~ $ 375 ~ $ 310 ~ $ 310 Tax impacts ~ (105) ~ (105) ~ (87) ~ (87) Amortization of Wildfire Fund contribution (post-tax) ~ $ 270 ~ $ 270 ~ $ 223 ~ $ 223 (2) “Amortization of Wildfire Fund contribution” represents the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability. Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 4 and 2025 Earnings Guidance

43 Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance (4) “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 any earnings-impacting investment losses or gains associated with investments related to the contributions to the customer credit trust. (3) “Bankruptcy and legal costs” consists of legal and other costs associated with PG&E Corporation’s and the Utility’s Chapter 11 filing. 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range Legal and other costs ~ $ 90 ~ $ 45 ~ $ 65 ~ $ 20 Bankruptcy and legal costs ~ $ 90 ~ $ 45 ~ $ 65 ~ $ 20 Tax impacts ~ (25) ~ (13) ~ (18) ~ (6) Bankruptcy and legal costs (post-tax) ~ $ 65 ~ $ 32 ~ $ 47 ~ $ 14 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range SB 901 securitization charge ~ $ 35 ~ $ 35 ~ $ 35 ~ $ 35 SB 901 securitization ~ $ 35 ~ $ 35 ~ $ 35 ~ $ 35 Tax impacts ~ (10) ~ (10) ~ (10) ~ (10) SB 901 securitization (post-tax) ~ $ 25 ~ $ 25 ~ $ 25 ~ $ 25 Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 4 and 2025 Earnings Guidance

44 (6) “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. (5) “Investigation remedies” includes the settlement agreement resolving the Safety and Enforcement Division’s investigation into the 2020 Zogg fire, the Wildfires OII decision different, costs related to the Paradise restoration and rebuild, and the locate and mark OII system enhancements. 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range 2020 Zogg fire settlement ~ $ 60 ~ $ 60 ~ $ 60 ~ $ 60 Wildfires OII disallowance and system enhancements ~ 10 ~ 10 ~ 30 ~ 30 Paradise restoration and rebuild ~ 5 ~ 5 ~ 5 ~ 5 Locate and mark OII system enhancements ~ 5 ~ 5 ~ — ~ — Investigation remedies ~ $ 80 ~ $ 80 ~ $ 95 ~ $ 95 Tax impacts ~ (21) ~ (21) ~ (27) ~ (27) Investigation remedies (post-tax) ~ $ 59 ~ $ 59 ~ $ 68 ~ $ 68 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range 2011-2014 GT&S capital audit ~ $ (35) ~ $ (35) ~ $ (20) ~ $ (20) Prior period net regulatory impact ~ $ (35) ~ $ (35) ~ $ (20) ~ $ (20) Tax impacts ~ 10 ~ 10 ~ 6 ~ 6 Prior period net regulatory impact (post-tax) ~ $ (25) ~ $ (25) ~ $ (14) ~ $ (14) Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 4 and 2025 Earnings Guidance

45 Undefined, capitalized terms have the meanings set forth in PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q for the quarter ended September 30, 2024. (8) “Wildfire-related costs, net of recoveries” includes costs associated with the 2019 Kincade fire, 2020 Zogg fire, and 2021 Dixie fire, net of recoveries. 2024 2025 (in millions) Low guidance range High guidance range Low guidance range High guidance range 2019 Kincade fire-related third-party claims ~ $ 75 ~ $ 75 ~ $ — ~ $ — 2019 Kincade fire-related costs ~ 10 ~ 10 ~ 10 ~ 10 2020 Zogg fire-related legal settlements ~ 5 ~ 5 ~ 5 ~ 5 2020 Zogg fire-related insurance recoveries ~ (5) ~ (5) ~ (5) ~ (5) 2021 Dixie fire-related legal settlements ~ 15 ~ 15 ~ 20 ~ 20 Wildfire-related costs, net of recoveries ~ $ 100 ~ $ 100 ~ $ 30 ~ $ 30 Tax impacts ~ (28) ~ (28) ~ (8) ~ (8) Wildfire-related costs, net of recoveries (post-tax) ~ $ 72 ~ $ 72 ~ $ 22 ~ $ 22 Exhibit C: PG&E Corporation's 2024 Earnings GuidanceExhibit C: PG&E Corpor tion's 20 4 and 2025 Earnings Guidance (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. The after-tax low and high non-core guidance range is $70 million for 2024.

46 Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 PG&E Corporation’s Net Income on a GAAP basis $ 579 $ 351 $ 1,838 $ 1,333 Income tax provision (benefit) (106) (416) 15 (1,099) Other income, net (83) (62) (241) (213) Interest expense 795 682 2,322 1,924 Interest income (156) (154) (495) (409) Operating Income $ 1,029 $ 401 $ 3,439 $ 1,536 Depreciation, amortization, and decommissioning 1,059 811 3,134 2,885 Wildfire Fund expense 139 219 295 453 Fire Victim Trust tax benefit, net of securitization 42 345 43 884 Investigation remedies 24 4 45 27 Prior period net regulatory impact (8) (8) (24) (24) Strategic repositioning costs — 1 — 4 Wildfire-related costs, net of recoveries 82 12 92 87 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 2,367 $ 1,785 $ 7,024 $ 5,852 Year to Date, 2024 vs. 2023 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

47 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 E: Non-GAAP Financial MeasuresExhibit E: Non A P Financial Measures Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance