2024 FIRST QUARTER EARNINGS Performance Is Power April 25, 2024

2 Forward-Looking Statements 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 non-GAAP core earnings), equity needs, 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 2020 Zogg 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, the application to transfer non-nuclear generation assets, and other matters; • the outcome of self-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 ability of PG&E Corporation and the Utility to finance through securitization up to $1.385 billion of remaining fire risk mitigation capital expenditures that were or will be incurred by the Utility; • 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 March 31, 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 April 25, 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 April 25, 2024 and is also available on PG&E Corporation’s website at www.pgecorp.com.

3 Endnotes are included in the Appendix. Reaffirming Guidance… …For Customers AND Investors NON-GAAP CORE EPS1 On Track For Guidance Differentiated Wildfire Risk Mitigation Affordability Commitment Constructive Regulatory Support 2024-2028 Financing Plan KEY TAKEAWAYSRESULTS First Quarter 37¢ ON TRACK GUIDANCE $1.33 - $1.37 2024 Guidance 10% At least 2024 9% At least 2025 - 2028 Reaffirmed No New Equity In 2024

4 Endnotes are included in the Appendix. California Wildfire Risk Framework… …Sector-Leading Protection 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 $2.7B 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 • 2023 WMP delivered 94% wildfire risk reduction3 94% Wildfire Risk Reduction3

5 Endnotes are included in the Appendix. 134 201 91 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Physical Risk Mitigations… …Are Reducing Ignitions 2 PSPS Events94% Wildfire Risk Reduction1 0 Catastrophic Wildfires HFTD + HFRA Weather-Normalized Ignition Rates R3+ per 100k Circuit Mile Days Cumulative CPUC-Reportable2 Ignitions in HFTD + HFRA 20172023 2022 2021 68% IGNITIONS DOWN vs. 2017 71% IGNITION RATE DOWN vs. 2017 2023 Data updated as of 12/31/2023 65 3.23 2.67 2.25 2.76 1.93 0.95 2017 2018 2019 2020 2021 2022 2023 0.93

6 Endnotes are included in the Appendix. PLAN1 Simple, Affordable Model… …Key To Building Trust Customer Capital Investment ~9% Enablers -O&M cost reduction (non-fuel)2 2% -Electric load growth3 1% - 3% -Other (including efficient financing)4 2% Subtotal 5% - 7% Customer Bills: At or Below Assumed Inflation 2% - 4%

7 Endnotes are included in the Appendix. Affordable Business Model… …Delivers Bills Below Inflation Combined Electric & Gas Monthly Bill: Residential Bundled Non-CARE GRC Deferred Collections Roll Off ▪ 2022 WMCE IRR ▪ 2023 GRC Collections One-Time Deferred Recovery 2% - 4% Average Annual Increase 2023 - 2026 230 240 250 260 270 280 290 300 2023 2024 2025 2026 Monthly Bill Forecast ($)1

8 GRC Authorizes Substantial Investments… …That Deliver Lasting Value For Customers Electric Reliability & Capacity ▪ Replacing 66,000 overhead poles ▪ Inspecting 2 million poles ▪ Replacing and/or maintaining 178,000 units of overhead and underground distribution line equipment ▪ Replacing 960 overhead transformers for capacity increases ▪ Maintenance on 93,000 units of substation equipment Wildfire Mitigation & System Hardening ▪ Installing 10,500 units of equipment for wildfire mitigation ▪ Undergrounding 1,230 miles in high fire risk areas Gas System Improvements ▪ Replacing 163 miles of distribution pipeline ▪ Inspecting 343 miles of transmission pipeline ▪ Strength-testing 43 miles of gas transmission pipeline

9 Performance Playbook: Work Bundling …Delivering Predictable Results Savings & Efficiencies ▪ At least $20 million customer savings this year ▪ Better negotiated bundled contract pricing ▪ Crew planning and execution efficiencies ▪ Assembly line style production ▪ Reduced outages for customers ▪ Reduced truck rolls Mega Bundle Circuit Project: a circuit-based approach, where all work funded on a circuit becomes a single scope of work made up of many smaller scopes including poles, tags, and switches. Waste Elimination DRIVES

10 Endnotes are included in the Appendix. Non-GAAP Core EPS1 Comparison… …On Track For 2024 Guidance Of $1.33-$1.37 Factors Q2 through Q4 Customer Capital Investments Operating & Maintenance Savings Redeployment 32¢ 3¢ 29¢ 37¢ 1¢ (2¢) First Quarter Operating & Maintenance Savings 2024 First Quarter 2023 First Quarter Customer Capital Investment Redeployment 6¢ GRC Benefit2 As Reported

11 Endnotes are included in the Appendix. Sector-Leading Rate Base Growth… …Benefits Customers And Supports Earnings Growth Plus at least customer beneficial investment opportunities4 1 Transportation Electrification Capacity Investments 3 Incremental New Business Connections 4 Hydro & Storage 5 IT & Automation 2 Transmission Upgrades: Data Centers & System Investments ~9.5% CAGR 2023-2028 CPUC FERC % already authorized2 91% 90% 84% 80% $62B 2024-2028 +20% vs. $52B 2023-2027 Weighted Average Rate Base ($B)1 CapEx ($B)3 11 11 12 13 14 15 46 52 56 60 68 75 57 63 68 73 82 90 2023A 2024F 2025F 2026F 2027F 2028F 1.4 1.5 2.1 1.8 1.8 1.9 8.4 8.8 10.6 9.7 11.8 12.1 9.8 10.4 12.7 11.5 13.6 14.0 2023A 2024F 2025F 2026F 2027F 2028F 93% $5B

12 Endnotes are included in the Appendix. Capital Investment For Customers… …Also Improves Cash Flow $5 $8 $11 -$4 -$2 -$3 -6 -4 -2 0 2 4 6 8 10 12 14 2023A 2024F 2025F 2026F 2027F 2028F Capital Investment1 Amount (billions) $ Operating Cash Flow Cash Flow Pre-Dividend FFO/Debt2 2024 Cash Flow Drivers • 2023 GRC Catch-Up • 2024 GRC Revenue • Interim Rate Relief Mid teens

13 Five-Year Financing Plan… …Supports Customer Capital Investment 2024-2028 (excludes proposed Pac Gen sale) $50 $62 (2½) (11) 11 14 (2½) 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 Debt Retired & Other Equity Issuance CapEx Amount (billions) $ $62

14 Endnotes are included in the Appendix. Credit Rating Improvements1… …Helps Make Customer Investments Affordable Scale Moody's S&P / Fitch Moody’s S&P Fitch A2 A Investment Grade A3 A- Baa1 BBB+ Baa2 BBB Baa3 BBB- Sub-Investment Grade Ba1 BB+ Ba2 BB Ba3 BB- Outlook Stable Present 2020 Positive Positive Present 2020 Issuer Credit Rating2 Utility Secured Rating

15 Endnotes are included in the Appendix. Simple, Affordable Model… …Creates Room For Customer Capital Investment Examples of O&M Cost Reductions (Non-Fuel) 2022 Actual 2023 Actual 2024 Plan Long-Term Plan Good Business Decisions and Savings Through Lean (millions) (millions) (millions) (millions) - Resource Management $ 25 $ 90 $ 65 $ 65 - Efficiencies & Insurance 270 350 150 50 - Capital Conversion 100 - 5 30 30 - Planning, Execution, and Automation 50 130 155 195 Net Cost Increases (115) (60)6 (200) (140) Net Savings $ 330 $ 510 $ 200 $ 200 Percent Savings MODEL1 PLAN Customer Capital Investment ~9% Enablers -O&M cost reduction (non-fuel)2 2% -Electric load growth3 1% - 3% -Other (including efficient financing)4 2% Subtotal 5% - 7% Customer Bills: At or Below Assumed Inflation 2% - 4% 5½%3% 2% 2% Efficient Financing

16 Working With Policymakers And Stakeholders… …To Execute Our Plan Financial Risk Mitigation Physical Risk Mitigation Jun 2023 2022 WMCE Interim Rate Relief Jan 2024 2023 Safety Certificate Issued May 2023 Safety Culture Proceeding Resolved Jan 2023 Wildfire Self- Insurance Settlement May 2023 Zogg Fire Settlement Approved Oct 2023 SB 410 Signed TBD 2024 Pacific Generation Final Decision TBD 2024 File 10-Year Under- grounding Plan Nov 2023 Diablo Canyon NRC Filing Late Q2 2024 GRC “Capacity Phase” Proposed Decision Dec 2023 2023 WMP Final Decision Jan 2024 Dixie Fire Settlement Approval Sep 2023 2023 GRC Proposed Decisions Oct 2023 FERC TO21 Filing Nov 2023 2023 GRC Final Decision Dec 2023 Cost of Capital AL Approval Mar 2024 2023 WGSC Interim Rate Relief Final Decision May 2024 File Climate Adaptation Vulnerability Assessment

17 Endnotes are included in the Appendix. Differentiated Performance… …Benefits Customers AND Investors 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% Operating Cashflow $3.7B $4.7B $8.3B $10B+ Performance Playbook Enterprise Lean Maturity N/A 44% 51% 80% Risk Reduction Safety Certification Valid through 1/22/25 Financial S&P 500 / Rate Neutral Securitization Common Dividend / Fire Victim Trust Exit 2% - 4% Premium Multiple 1 - 3 2% - 4% Investment Grade Premium Multiple 5½% 2% At Least 10% At Least 9% 2025 - 2028

18 Endnotes are included in the Appendix. Differentiated Growth And Regulatory Visibility… …Building Trust With Customers AND Investors PREMIUM RATE BASE & CORE EPS GROWTH1 NON-FUEL O&M REDUCTIONS4 LOAD GROWTH3 2023 share of new registrations in service area vs. 23% in 2022 Projecting ~70% increase in load growth over the next 20 years 3x increase in data center applications in 2023 compared to prior 4 years 28% EVs REGULATORY & POLICY ENVIRONMENT 4-Year Revenue Certainty Fair ROE Cost of Capital Adjustment Mechanism Constructive Legislation SB 884, SB 846, SB 410 CA Carbon Neutrality by 2045 $1.00 2 $1.10 $1.23 10% 9% 9% 9% 9% 21A 22A 23A 24F 25F 26F 27F 28F 2022A 3% 2023A 5½% 2024F 2% 57 63 68 73 82 90 23A 24F 25F 26F 27F 28F $B -5½% -6 0 6 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 2017-2021 Average5 Percent PG&E PG&E -3% 22 23 Peers ~9.5% CAGR

Q&A Carolyn Burke EVP, Chief Financial Officer Patti Poppe Chief Executive Officer Investor Meeting June 12, 2024 New York

21 Table of Contents Appendix # Title Slide (Link) Appendix 1 2024 Factors Impacting Earnings Slide 22 Appendix 2 GRC Final Decision Slide 23 Appendix 3 Expected Recovery of Wildfire-Related Costs Slide 24 Appendix 4 AB 1054 Protections Slide 25 Appendix 5 SB 846 Diablo Canyon Legislation Slide 26 Appendix 6 Pacific Generation Minority Sale Slide 27 Appendix 7 Wildfire Mitigation Plan Progress Slide 28 Appendix 8 Physical Risk Mitigation Then & Now Slide 29 Appendix 9 PG&E Utility Securitization Program Slide 30 Appendix 10 Regulatory Progress Slide 31 Appendix 11 Presentation Endnotes Slide 32-34 Appendix 12 Supplemental Earnings Materials Slide 35-46

22 Endnotes are included in the Appendix. Changes from prior quarter noted in blue Non-Core Items5 Key Factors Affecting Non-GAAP Core Earnings7 ($ millions after tax) Unrecoverable net interest8 $285 - $365 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs Weighted Average Rate Base2 ($ millions after tax) Estimated non-core items guidance $360 - $380 Non-core items cash portion6 $290 CPUC $52B FERC $11B Total Rate Base $63B Equity Ratio:3 52% Return on Equity:3 10.7%4 Key Ranges Non-GAAP Core EPS1 $1.33 - $1.37 New Equity in 2024 $0 Appendix 1: 2024 Factors Impacting Earnings

23 Appendix 2: GRC Final Decision 2023 2024 2025 2026 $13.52 $14.24 $14.60 $14.80 Revenue Catch-Up • Cash collection of 2023 incremental revenue requirement • Softens 2024 rates and lowers bills in 2026 Escalation • Increases reflecting incremental inflation in 2021 and 2022 Undergrounding • Adopts over 60% of requested 2023-2026 miles • Permanent wildfire risk reduction Wildfire Mitigation • Funds critical wildfire risk mitigation programs Authorized Miles EPSS & PSPS Month Amortization Funds 163 miles per year for gas distribution pipe replacement Fully funds requested annual energization work Revenue Requirement $B IMPROVED 36 24 25% 50% IMPROVED IMPROVED 973 1,230 RESTORED

24 Appendix 3: Expected Recovery Of Wildfire-Related Costs Recovery Status as of March 31, 2024 $0.8B Approved $2.4B Pending $1.2B Yet to be Filed $4.4B Total $ billions 1.1 1.2 1.2 1.2 2.6 1.6 1.0 0.6 0.9 0.2 4.6 3.0 2.2 1.8 Dec 23A Dec 24F Dec 25F Dec 26+ F Recovery Outstanding By Year 2021 WMCE $568M 2022 WMCE $336M 2023 WMCE $1,030M 2023 WGSC $483M

25 Endnotes are included in the Appendix. Protections Offered Under AB 1054 Appendix 4: AB 1054 Protections Physical Risk Reduction Drives Financial Protections • Liquidity available as soon as claims paid exceed $1B2 • Wildfire Fund with $21B claims paying capacity (sized to last 20 years) Liquidity Available when needed Cost Recovery Improved prudency standard1 Reimbursement Maximum liability capped • Utility conduct presumed prudent • Can apply to CPUC for recovery of claims above insurance but below $1B • Beginning in 2023, self-insurance applies • If found imprudent: reimburse Wildfire Fund • Obligation capped at 20% of electric T&D equity rate base, 3 Yr rolling basis (~$4.1B)3 • If found prudent: no Wildfire Fund reimbursement required Physical Risk Mitigations1 Approved Wildfire Mitigation Plan (WMP) 2 Wildfire Safety Certification3

26 Endnotes are included in the Appendix. 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 Appendix 5: SB 846 Diablo Canyon Legislation 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 TBD NRC Environmental Impact Statement & Safety Evaluation Report

27 Endnotes are included in the Appendix. Appendix 6: Pacific Generation Minority Sale ~$3.4B 2023 Rate Base1 Generation Capacity Corporate Structure and Return ▪ Pacific Generation will be a stand-alone PG&E subsidiary with separate management and Board ▪ Revenue requirement would be set through the GRC and cost of capital proceedings, essentially unchanged from the current process ▪ Pacific Generation would be capitalized in line with authorized CPUC capital structure Hydro 2,700 MW Battery and Pumped Storage 1,350 MW Natural Gas 1,400 MW Solar 152 MW 5.6GW Efficient Financing ▪ Sale proceeds reinvested into PG&E system ▪ Retain owned-generation benefits with no rate impact ▪ Additional capital source for generation safety, reliability and clean energy investments ▪ Credit positive transaction Customers Investors AND 9/28/22 Application (A.22-09-018) and testimony filed 9/28/22 3/15/24 Proposed Decision received April 2024 Proposed Decision held by CPUC Staff to 5/9/24

28 Appendix 7: Wildfire Mitigation Plan Progress 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

29 Appendix 8: Physical Risk Mitigation Progress Then & Now High-Definition Cameras with AI Capability Weather Stations Hazard Awareness Warning Center Advanced Meteorology & Fire Science Models ASSET IMPROVEMENTS Undergrounding System Hardening Sectionalizing Devices Trees Removed SITUATIONAL AWARENESS 2017 2023 OPERATIONAL MITIGATIONS EPSS PSPS 10K UG Program HD Cameras Weather Stations Wildfire Mitigation Plan EPSS Partial voltage force out Transmission operational controls PSPS Safety & infrastructure protection teams Downed conductor detection New or Expanded in 2023 MILES COMPLETED 664 LINE MILES HARDENED 1,671 DEVICES INSTALLED 1,427 TREES REMOVED 3.3M 2019-2023 Actuals CAMERAS INSTALLED 602 STATIONS INSTALLED 1,424 MONITORING 24/7/365

30Changes from prior quarter noted in blue The Utility has completed $9.3B of $10.7B expected securitization issuances • AB 1054 signed into law on July 12, 2019 • Up to $3.2B across several bond issuances • Reimburse capital expenses associated with wildfire risk mitigation • 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 • $860M recovery bonds issued in November 2021 • $983M recovery bonds issued in November 2022 • Third issuance expected Q2-Q3 2024 • SB 901 signed into law on September 21, 2018 • Up to $7.5B in up to three issuances by December 31, 2022 • Pay or reimburse the Utility for incurred costs and expenses relating to catastrophic wildfires ignited in 2017 • Financing order issued on May 11, 2021 • Financing order became final, non-appealable February 28, 2022 Issuances complete • $3.6B issued in May 2022 • $3.9B issued in July 2022 Statutory Authority: Total Issuance Amount: Use of Proceeds: Financing Order: Securitization Timing: Rate Neutral Securitization A.20-04-023 AB 1054 Securitization A.22-03-010 Complete Appendix 9: PG&E Utility Securitization Program

31 Endnotes are included in the Appendix. Changes from prior quarter noted in blue Regulatory Case/Filing Docket Status as of April 2024 Expected Milestones1 2023 GRC A.21-06-021 2023 GRC Application filed 6/30/21 Wildfire Self-Insurance Final Decision received 1/12/23 Phase 2 Testimony submitted 9/15/23 Final Decision received 11/16/23 Phase 2 “Capacity Phase” Proposed Decision Late Q2 2024 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 Opening Testimony submitted 1/29/2024. ACCAM Tier 2 Advice Letter approved 12/22/23 (4813-G/7046-E) 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 Proposed Decision Q2 2025 2022 Wildfire Mitigation Plan 2022-WMPs R.18-10-007 Final Decision by OEIS received 11/10/22 CPUC ratified 12/15/22 2023 Wildfire Mitigation Plan 2023-2025-WMPs Submitted 3/27/23 Revision Notice issued 6/22/23 Final Decision by OEIS received 12/29/23 CPUC ratified 2/15/24 2022 Safety Certificate 2022-SCs Submitted 9/14/22 Safety Certificate issued by OEIS 12/13/22 2023 Safety Certificate 2023-SCs Filed 12/1/23 Safety Certificate issued by OEIS 1/22/24 Minority Interest Sale in Pacific Generation LLC A.22-09-018 Filed 9/28/22 Schedule modified on 3/30/23 Proposed Decision issued on 3/15/24 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 2025 Appendix 10: Regulatory Progress

32 Slide titles are hyperlinksSlide 3: Reaffirming Guidance 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 12, 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 12, Exhibit E regarding non-GAAP financial measures. Slide 4: 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. Based on a comparison in the Utility's GRC testimony of the wildfire risk score for a baseline risk level to a risk level ref lecting the Utility’s mitigation work. Risk scores are calculated using the scoring methodology established by the CPUC in the Safety Model Assessment Proceeding, which reflects the frequency with which various risks are expected to occur and the potential safety, reliability, and financial impacts of varying degrees of wildfire severity. Slide 5: Physical Risk Mitigations 1. Based on a comparison in the Utility's GRC testimony of the wildfire risk score for a baseline risk level to a risk level ref lecting the Utility’s mitigation work. Risk scores are calculated using the scoring methodology established by the CPUC in the Safety Model Assessment Proceeding, which reflects the frequency with which various risks are expected to occur and the potential safety, reliability, and financial impacts of varying degrees of wildfire severity. 2. A reportable fire incident per Decision 14-02-015 is a fire event that meets the following criteria: 1) ignition is associated with the Utility's power lines (either transmission or distribution), 2) something other than the Utility's facilities burned, and 3) the resulting fire travelled more than one meter from the ignition point. Slide 6: 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, redeployment above base plan, property taxes, and 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. Reductions available for redeployment. 3. Expected drivers of forecasted electric load growth include electrification and electric vehicle adoption. 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 7: Affordable Business Model 1. 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. This forecast assumes procurement costs remain constant. Slide 10: Non-GAAP Core EPS Comparison 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 12, 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 12, 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 quarter 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 quarter of 2023. See Appendix 12, 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 quarter of 2024. Slide 11: Sector-Leading Rate Base Growth 1. Weighted-average rate base is the Utility’s equity rate base including non-nuclear generation assets. 2. Percentage already authorized represents the portion of CPUC-jurisdictional rate base adopted in the 2023 GRC for years 2023 through 2026 and holding constant in 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. Rate base point estimates reflect authorized capital expenditures from the 2023 GRC final decision (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. 4. Investment opportunities of at least $5 billion are not reflected in the CapEx or rate base numbers. Appendix 11: Presentation Endnotes

33 Slide titles are hyperlinksSlide 12: Capital Investment For Customers 1. Capital Investment, as presented, is equivalent to Cash from Investment Activities on the Statement of Cash Flows, and as such, includes CapEx, contributions and withdrawals from the customer credit trust, and certain other Balance Sheet items. 2. 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 the comparable future period FFO/Debt. 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: 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, redeployment above base plan, property taxes, and 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. Reductions available for redeployment. 3. Expected drivers of forecasted electric load growth include electrification and electric vehicle adoption. 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. Denoted amount is immaterial. 6. 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 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, redeployment above base plan, property taxes, and 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. Reductions available for redeployment. 2. Expected drivers of forecasted electric load growth include electrification and electric vehicle adoption. 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 12, 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 12, Exhibit E regarding non-GAAP financial measures. 5. CAGR is from 2023 through 2028. Appendix 11: Presentation Endnotes

34 Slide titles are hyperlinks Appendix 11: Presentation Endnotes Slide 18: Differentiated Growth And Regulatory Visibility 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 12, 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 12, 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. Expected drivers of forecasted electric load growth include electrification and electric vehicle adoption. 4. 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. 2% reduction calculated based on the prior year’s operating and maintenance costs, excluding non-core items, balancing account deferrals, redeployment above base plan, property taxes, and 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. Reductions available for redeployment. 5. Excludes fuel, purchased power costs, employee pensions and benefits, and injuries and damages for all utilities other than PG&E. The five-year average is calculated from 2017 through 2021. List of Peers: Alliant Energy Corporation, Ameren Corporation, American Electric Power Company Inc., CMS Energy Corporation, Consolidated Edison Inc., DTE Energy Company, Duke Energy Corporation, Edison International, Evergy Inc., Eversource Energy, NiSource Inc., Pinnacle West Capital Corporation, The Southern Company, WEC Energy Group Inc., and Xcel Energy Inc. Slide 22: Appendix 1: 2024 Factors Impacting Earnings 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 12, Exhibit C for a reconciliation of EPS guidance on a GAAP basis to non-GAAP core earnings per share and Appendix 12, 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. On January 12, 2024, parties submitted a late-filed request for CPUC review of Energy Division’s December 22, 2023 approval of the Utility's cost of capital adjustment mechanism advice letter. In the meantime, the advice letter remains in effect and provides for a 10.7% ROE; the unrecoverable net interest range reflects a benefit of $80 million after tax from the cost of debt reset. 5. Refer to Appendix 12, Exhibit C: PG&E Corporation's 2024 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 2024 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 4: AB 1054 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. 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 26: Appendix 5: 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 27: Appendix 6: Pacific Generation Minority Sale 1. Reflects non-nuclear generation rate base authorized in the 2023 GRC. Slide 31: Appendix 10: Regulatory Progress 1. Regulatory proceeding timelines reflect expected filing and decision time frames; actual timing may differ.

35 Appendix 12: 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 36-39 Exhibit B Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share (“EPS”) Slides 40 Exhibit C PG&E Corporation’s 2024 Earnings Guidance Slides 41-44 Exhibit D GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation Slides 45 Exhibit E Non-GAAP Financial Measures Slides 46

36 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 Three Months Ended March 31, Earnings Earnings per Common Share (in millions, except per share amounts) 2024 2023 2024 2023 PG&E Corporation’s earnings/EPS on a GAAP basis $ 732 $ 569 $ 0.34 $ 0.27 Non-core items: (1) Amortization of Wildfire Fund contribution (2) 56 84 0.03 0.04 Bankruptcy and legal costs (3) 12 17 0.01 0.01 Fire Victim Trust tax benefit net of securitization (4) (2) (74) — (0.03) Investigation remedies (5) 4 15 — 0.01 Prior period net regulatory impact (6) (6) (6) — — Strategic repositioning costs (7) — 1 — — Wildfire-related costs, net of insurance (8) 4 9 — — PG&E Corporation’s non-GAAP core earnings/EPS (9) $ 800 $ 615 $ 0.37 $ 0.29 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. Earnings per Common Share is calculated based on diluted shares. Amounts may not sum due to rounding. First 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.

37 First Quarter, 2024 vs. 2023 (in millions, except per share amounts) (3) PG&E Corporation and the Utility recorded costs of $17 million (before the tax impact of $5 million) during the three months ended March 31, 2024 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 $78 million (before the tax impact of $22 million) during the three months ended March 31, 2024, 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 a net gain of $3 million (before the tax impact of $1 million) during the three months ended March 31, 2024 related to any earnings-impacting investment losses or gains associated with investments related to the contributions to the customer credit trust. Previously included the charge related to the establishment of the SB901 securitization regulatory asset and the SB901 securitization regulatory liability associated with revenue credits funded by the net operating loss monetization and tax benefits related to the Fire Victim's Trust's sale of PG&E corporation common stock.

38 First Quarter, 2024 vs. 2023 (in millions, except per share amounts) (in millions) Three Months Ended March 31, 2024 Wildfires OII disallowance and system enhancements $ 2 Locate and mark OII system enhancements 1 Paradise restoration and rebuild 1 2020 Zogg fire settlement 1 Investigation remedies (pre-tax) $ 4 Tax impacts — Investigation remedies (post-tax) $ 4 (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) during the three months ended March 31, 2024 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.

39 First Quarter, 2024 vs. 2023 (in millions, except per share amounts) (9) “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 March 31, 2024. (8) Includes costs associated with the 2019 Kincade fire and 2021 Dixie fire, net of insurance, as shown below. (in millions) Three Months Ended March 31, 2024 2019 Kincade fire-related costs $ 2 2020 Zogg fire-related insurance recoveries — 2020 Zogg fire-related legal settlements — 2021 Dixie fire-related legal settlements 2 Wildfire-related costs, net of insurance (pre-tax) $ 5 Tax impacts (1) Wildfire-related costs, net of insurance (post-tax) $ 4 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 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 first quarter of 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 programs such as the increase of gas transmission project work being capitalized during the three months ended March 31, 2024. (4) Represents redeployment of operating and maintenance savings to fund incremental work such as increased transmission system inspections and electric asset mapping during the three months ended March 31, 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, and the timing of capitalized overheads and A&G costs allocated to capital projects during the three months ended March 31, 2024. First Quarter 2024 vs. 2023 Earnings Earnings per Common Share 2023 Non-GAAP Core Earnings/EPS (1) $ 615 $ 0.29 2023 GRC benefit (2) 62 0.03 Customer capital investment 137 0.06 Operating & maintenance savings (3) 14 0.01 Redeployment (4) (23) (0.02) Timing and other (5) (4) — 2024 Non-GAAP Core Earnings/EPS (1) $ 801 $ 0.37 First 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")

41 2024 EPS guidance Low High Estimated EPS on a GAAP basis ~ $ 1.15 ~ $ 1.20 Estimated non-core items: (1) Amortization of Wildfire Fund contribution (2) ~ 0.10 ~ 0.10 Bankruptcy and legal costs (3) ~ 0.03 ~ 0.01 SB 901 securitization (4) ~ 0.01 ~ 0.01 Investigation remedies (5) ~ 0.04 ~ 0.04 Prior period net regulatory impact (6) ~ (0.01) ~ (0.01) Wildfire-related costs, net of insurance (7) ~ 0.01 ~ 0.01 Estimated EPS on a non-GAAP core earnings basis ~ $ 1.33 ~ $ 1.37 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, 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 (in millions, pre-tax) Low guidance range High guidance range Amortization of Wildfire Fund contribution ~ $ 305 ~ $ 305 Amortization of Wildfire Fund contribution (pre-tax) ~ $ 305 ~ $ 305 Tax impacts ~ (85) ~ (85) Amortization of Wildfire Fund contribution (post-tax) ~ $ 220 ~ $ 220 (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 Guidance

42 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 (in millions, pre-tax) Low guidance range High guidance range Legal and other costs ~ $ 75 ~ $ 30 Bankruptcy and legal costs (pre-tax) ~ $ 75 ~ $ 30 Tax impacts ~ (21) ~ (8) Bankruptcy and legal costs (post-tax) ~ $ 54 ~ $ 22 2024 (in millions, pre-tax) Low guidance range High guidance range SB 901 securitization charge ~ $ 33 ~ $ 33 Net gains related to customer credit trust ~ (3) ~ (3) SB 901 securitization (pre-tax) ~ $ 30 ~ $ 30 Tax impacts ~ (8) ~ (8) SB 901 securitization (post-tax) ~ $ 22 ~ $ 22 Exhibit C: PG&E Corporation's 2024 Earnings Guidance

43 (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 costs related to the Paradise restoration and rebuild, the Wildfires OII decision different, the settlement agreement resolving the Safety and Enforcement Division’s investigation into the 2020 Zogg fire, and the locate and mark OII system enhancements. 2024 (in millions, pre-tax) Low guidance range High guidance range 2020 Zogg fire settlement ~ 75 ~ 75 Wildfires OII disallowance and system enhancements ~ 40 ~ 40 Paradise restoration and rebuild ~ 10 ~ 10 Locate and mark OII system enhancements ~ 5 ~ 5 Investigation remedies (pre-tax) ~ $ 130 ~ $ 130 Tax impacts ~ (35) ~ (35) Investigation remedies (post-tax) ~ $ 95 ~ $ 95 2024 (in millions, pre-tax) Low guidance range High guidance range 2011-2014 GT&S capital audit ~ $ (35) ~ $ (35) Prior period net regulatory impact (pre-tax) ~ $ (35) ~ $ (35) Tax impacts ~ 10 ~ 10 Prior period net regulatory impact (post-tax) ~ $ (25) ~ $ (25) Exhibit C: PG&E Corporation's 2024 Earnings Guidance

44 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 March 31, 2024. (7) “Wildfire-related costs, net of insurance” includes legal and other costs associated with the 2019 Kincade fire, 2020 Zogg fire, and 2021 Dixie fire, net of insurance. 2024 (in millions, pre-tax) Low guidance range High guidance range 2019 Kincade fire-related costs ~ $ 15 ~ $ 15 2020 Zogg fire-related legal settlements ~ 5 ~ 5 2020 Zogg fire-related insurance recoveries ~ (5) ~ (5) 2021 Dixie fire-related legal settlements ~ 15 ~ 15 Wildfire-related costs, net of insurance (pre-tax) ~ $ 30 ~ $ 30 Tax impacts ~ (8) ~ (8) Wildfire-related costs, net of insurance (post-tax) ~ $ 22 ~ $ 22 Exhibit C: PG&E Corporation's 2024 Earnings Guidance

45 Three Months Ended March 31, (in millions) 2024 2023 PG&E Corporation’s Net Income on a GAAP basis $ 735 $ 572 Income tax benefit 39 (348) Other income, net (76) (85) Interest expense 715 602 Interest income (137) (112) Operating Income $ 1,276 $ 629 Depreciation, amortization, and decommissioning 1,022 1,077 Wildfire Fund expense 78 117 Fire Victim Trust tax benefit, net of securitization (3) 253 Investigation remedies 4 21 Prior period net regulatory impact (8) (8) Strategic repositioning costs — 2 Wildfire-related costs, net of insurance 5 13 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 2,374 $ 2,104 Year to Date, 2024 vs. 2023 1. Amounts may not sum due to rounding. “Non-GAAP Adjusted EBITDA” is a non-GAAP financial measure. 2. 2024 Non-GAAP Adjusted EBITDA differs from what was reported on May 4, 2023 (removed Bankruptcy and legal costs from the calculation). Exhibit D: GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation PG&E Corporation

46 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 2025-2028, 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 Measures