EX-99.2 3 q323earningspresentation.htm EX-99.2
2023 THIRD QUARTER EARNINGS Investing in California’s Prosperity October 26, 2023

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 2023 and 2024 non-GAAP core earnings), equity needs, rate base growth, capital expenditures, cost reductions, wildfire risk mitigation, 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 in the Utility’s territory, 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, and the timing of insurance recoveries; • 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 gas industries driven by technological advancements and a decarbonized economy; • a cyber incident, cyber security breach, severe natural event, or physical attack; • severe weather conditions, 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 the application to transfer non-nuclear generation assets; • 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 control operating costs, 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, 2022, their joint Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 (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 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 October 26, 2023. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation was attached to PG&E Corporation and the Utility’s joint Current Report on Form 8-K that was furnished to the SEC on October 26, 2023 and is also available on PG&E Corporation’s website at www.pgecorp.com.

3 Endnotes are included in the Appendix. Reaffirming Guidance… …Consistency For Customers AND Investors EPS New Equity 2023 $1.19-$1.23 Up at least 10% $0 2024 Up at least 10% $0 NON-GAAP CORE EPS1 ON TRACK Third Quarter 24¢ RESULTS 2023 and 2024 10% At least 2025 and 2026 9% At least EPS GROWTH GUIDANCE ON TRACK ON TRACK ON TRACK Year To Date 76¢

4 Endnotes are included in the Appendix. 2023: Mitigating Physical and Financial Risk… …And Earning Trust ▪ Simple, Affordable Model ▪ 2% Non-Fuel O&M Cost Reduction2 ▪ Waste Elimination ▪ Efficient Financing Customers ▪ Expanded Layers of Protection ▪ 2023 WMP: 94% risk reduction1 ▪ Protections in Place Regardless of Weather System Resilience ▪ Self-Insurance Approved ▪ NRC Waiver Granted ▪ 2022 WMCE Interim Rates ▪ Zogg and Dixie Fire Settlements ▪ SB 410 Energization Bill Constructive Policy Outcomes ▪ Non-GAAP Core EPS Growth3 • At Least 10% for 2023 and 2024 • At Least 9% in 2025 and 2026 ▪ Balance Sheet Focus ▪ No Equity Through 2024 ▪ Layers of Protection Investors

5 Endnotes are included in the Appendix. Building On Existing Layers Of Protection… …Increased Wildfire Risk Reduction To 94% In 2023 reduction in wildfire risk from PG&E equipment1 90% 94% reduction in wildfire risk from PG&E equipment1 100% 80% 60% 40% 20% 0% Wildfire Mitigation Programs (System Hardening/Undergrounding, Vegetation Management, Enhanced Inspections and Repairs) Enhanced Powerline Safety Settings (EPSS) Situational Awareness and Response Public Safety Power Shutoff (PSPS) New or expanded measures in 2023: Transmission Pole Clearing Transmission Operational Controls Partial Voltage Force Out Downed Conductor Detection Beyond Line-of-Sight Drone Inspection AI Capabilities for HD Cameras ACHIEVED

6 Endnotes are included in the Appendix. 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 132 186 85 Jan Mar May Jul Sep Nov 62 20172023 2022 2021 67% IGNITIONS DOWN vs. 2017 70% IGNITION RATE DOWN vs. 2017 3.34 2.72 2.07 2.86 1.98 1.09 2017 2018 2019 2020 2021 2022 2023 1.01 2023

7 2022 2023 2024 2025 2026 Electric + APD Gas + APD Customer Capital Investment Opportunities… …Add Another Layer Of Financial Protection (Actual) ▪ Improve on PD/APD ▪ WMCE Applications ▪ SB 410 Energization ▪ 10-Year Undergrounding ▪ FERC Transmission Customer Investments ▪ Lean Management ▪ Diablo Canyon Incentive ▪ Cost of Capital Adjustment Affordability Drivers CPUC Rate Base Weighted Average - $B $39B

8 Lean Playbook… …Drives Results Vacaville Undergrounding Project This undergrounding project was originally estimated to cost close to $3.5 million a mile with an expected completion date in 2024. The team is now estimating a unit cost of approximately $2.9 million a mile, and we’re slated to finish in early December 2023.

9 Endnotes are included in the Appendix. Metric Q3 2023 Status 2023 Goal Long-Term Goal Catastrophic Wildfires1 0 0 Undergrounding Circuit Miles 350 10,000 Annual O&M Cost Reduction (Non-Fuel)2 2% 2% Rate Base Growth3 ~9.5% CAGR 2022-2027 Non-GAAP Core EPS Growth4 At least 10% 2023 & 2024 at least 10% 2025 & 2026 at least 9% FFO/Debt5 Mid teens by 2024 PG&E Corporation Debt $2+ billion debt paydown by end of 2026 2023 Report Card… …Delivering Consistent, Predictable Results ON TRACK ON TRACK ON TRACK ON TRACK ON TRACK ON TRACK

10 Endnotes are included in the Appendix. First Nine Months Fourth Quarter Earnings Factors Non-GAAP Core EPS1 Comparison… …On Track For 2023 Guidance Of $1.19-$1.23 Redeployment Timing Other 2023 YTD Q3 Operating & Maintenance 2022 YTD Q3 84¢ 3¢ (3¢) (4¢) 76¢ (4¢) GRC Final Decision Timing Redeployment and Other

11 Customer Investment Grows… …To Do Good, Needed Work $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 CapEx Amount (billions) 2018-2022 Avg. $8B /year 2023-2027 Avg. $10B /year 2028-2032 Avg. $13B /year $ 16 14 12 10 8 6 4 2 Gas Elec. Transmission Customer & Connections Non-WF Risk Reduction Generation, IT & Other Wildfire Mitigation, System Hardening & Undergrounding Electric Distribution

12 Endnotes are included in the Appendix. Simple, Affordable Model… …Creates Room For Customer Capital Investment Examples of O&M Cost Reductions (Non-Fuel) Efficient Financing Sale of Minority Interest in Pac Gen/DOE Low-Cost Loan Program 2022 Actual 2023 Plan Long-Term Plan Good Business Decision (millions) (millions) (millions) - Attrition $ 25 $ 25 $ 25 - Efficiencies & Insurance 270 200 50 - Capital Conversion 100 50 25 - Automation 5 15 30 Savings Through Lean - Planning & Execution Improvements 45 100 150 Net Cost Increases (115) (190) (80) Net Savings $ 330 $ 200 $ 200 Percent Savings (Fast Start) 3% 2% 2% MODEL1 OPPORTUNITIES Customer Capital Investment ~9% Offsets -O&M cost reduction (non-fuel)2 2% -Electric load growth3 1% - 3% -Other (including efficient financing)4 2% Subtotal 5% - 7% Customer Impacts: At or Below Assumed Inflation 2% - 4% 2

13 Endnotes are included in the Appendix. Changes from prior quarter noted in blue 2022-2024 2025-2026 Non-GAAP Core EPS1 (CAGR) 10% Non-GAAP Core EPS Growth At least 10% At least 9% Dividend Eligibility achieved as of Q3 20232 Annual Non-GAAP Core EPS Growth & Dividend Yield At least 10% At least 10% Rate Base Growth (CAGR)3 ~9.5% O&M Cost Reduction (Non-Fuel)4 2% Annually FFO/Debt5 Mid teens by 2024 Value Proposition… …Better For Customers AND Investors

14 Working With Policymakers And Stakeholders… …To Execute Our Plan And Mitigate Physical And Financial Risk Financial Risk Mitigation Physical Risk Mitigation June 2023 2022 WMCE Interim Rate Relief Jan 2024 Pacific Generation Proposed Decision May 2023 Safety Culture Proceeding Resolved Jan 2023 Wildfire Self-Insurance Settlement May 2023 Zogg Fire Settlement Approved Oct 2023 SB 410 Signed Q4 2023 Diablo Canyon NRC filing Apr 2024 GRC Phase 2 Proposed Decision Dec 2023 2023 Safety Certificate Filing TBD File 10-Year Undergrounding Plan Nov 2023 2023 WMP Draft Decision Q4 2023 Dixie Fire Settlement Approval Sept 2023 2023 GRC Proposed Decisions Oct 2023 TO21 Filing Q4 2023 2023 GRC Final Decision Oct 2023 Cost of Capital AL Filing

Q&A Carolyn Burke EVP, Chief Financial Officer Patti Poppe CEO

Appendix

17 Table of Contents Appendix # Title Slide (Link) Appendix 1 2023 Factors Impacting Earnings Slide 18 Appendix 2 CapEx and Rate Base Slide 19 Appendix 3 Expected Recovery of Wildfire-Related Costs Slide 20 Appendix 4 2023 EPS Sensitivities Slide 21 Appendix 5 AB 1054 Protections Slide 22 Appendix 6 SB 846 Diablo Canyon Legislation Slide 23 Appendix 7 Wildfire Mitigation Plan Progress Slide 24 Appendix 8 PG&E Utility Securitization Program Slide 25 Appendix 9 Regulatory Progress Slide 26 Appendix 10 Presentation Endnotes Slide 27-29 Appendix 11 Supplemental Earnings Materials Slide 30-42

18 Endnotes are included in the Appendix. Non-Core Items4 Key Factors Affecting Non-GAAP Core Earnings6 ($ millions after tax) Unrecoverable interest expense7 $370 - $430 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs Weighted Average Rate Base2 ($ millions after tax) Estimated non-core items guidance $320 - $400 Non-core items cash portion5 $290 General Rate Case ~$44.5 - $48.5B Transmission Owner ~$11.5B Total Rate Base ~$56 - $60B Equity Ratio:3 52% Return on Equity:3 10.00% Key Ranges Non-GAAP Core EPS1 $1.19-$1.23 New Equity in 2023 and 2024 $0 Appendix 1: 2023 Factors Impacting Earnings Changes from prior quarter noted in blue

19 Endnotes are included in the Appendix. ~9.5% CAGR on equity rate base 2022-2027 $49.8 projected Weighted average rate base ($B) ~$56-$60 $67-$89 $60-$67 $62-$74 $65-$82 Transmission Owner Gas Transmission & Storage (GT&S) General Rate Case (GRC) Separately Funded Above Authorized GRC & GT&S rate cases combined starting in 2023 $9.6 $7.9-11.2 $7.9-$12.2 $8.0-$12.7 $8.1-$13.3 $8.1-$13.8 2022 Actual 2023 2024 2025 2026 2027 CapEx ($B)2 projected Subject to Ongoing and Future Recovery Requests • 2023 GRC request (September 2022 update filing) • Oakland HQ Purchase3 • Undergrounding • Transportation electrification Transmission Owner GRC and GT&S AB 1054 Fire Risk Mitigation4 Spend Above Currently Authorized Appendix 2: CapEx And Rate Base Upside Opportunities (+$5B CapEx)1 Growth • Transmission • Distribution Generation • Hydro • Storage Efficiency • IT & Automation • Waste Elimination • Sourcing 2022 Actual 2023 2024 2025 2026 2027

20 Endnotes are included in the Appendix. Appendix 3: Expected Recovery Of Wildfire-Related Costs Amounts may not sum due to rounding. Expected Cash Flow Recovery from Previously Incurred Wildfire-Related Spend $1.3B Approved $2.0B Pending $2.7B Yet to be Filed Approved Cost Recovery (Final Decisions) Expected Rate Recovery by Year Application Recovery Through Balance at 6/30/2023 QTD 2023 Expense QTD Rate Recovery As of 9/30/2023 2023 2024 2025+ 2020 GRC1 Dec-23 410 (16) (195) 199 199 2020 WMCE Feb-25 523 - (77) 446 75 318 54 2021 WMCE Dec-26 659 25 (18) 666 77 358 232 Total 1,593 9 (290) 1,312 351 675 286 Pending & Future Cost Recovery (Settled, Filed or Yet to be Filed) Expected Rate Recovery by Year Application Expected Amortization Balance at 6/30/2023 QTD 2023 Expense QTD Rate Recovery QTD Filings As of 9/30/2023 2023 2024 2025+ 2021 WMCE 24 months 592 - - - 592 592 2022 WMCE 24 months 1,172 2 (265) - 909 269 589 50 2023 WGSC 24 months 476 36 - - 511 72 375 64 Yet to be Filed TBD 2,157 513 - - 2,670 2,670 Total 4,398 550 (265) - 4,683 342 964 3,377

21 Sensitivity EPS Mitigation Sales Volume Electric Sales (GWh) +/- 1% 0¢ Decoupled Gas Sales (Bcf) +/- 1% 0¢ Decoupled Commodity Prices Power Prices CAISO NP15 ($/MWh) +/- $1 0¢ Regulatory Deferrals; ERRA, Supply PPAs Natural Gas Price PG&E Gate ($/MMBtu) +/- 50¢ 0¢ Monthly True-Up; Hedging Allowed ROE CPUC FERC +/- 1% +/- 1% 0¢ 0¢ 3-Year Cost of Capital TO20 Settlement Interest Rates +/- 100 bps +/- 2¢ Efficient Financing; Balancing Account Interest; Cost of Capital Adjustment Mechanism O&M +/- 1% +/- 2¢ Simple, Affordable Model Pension Assumed Return Discount Rate +/- 1% +/- 1% 0¢ 0¢ Long Established Regulatory Recovery Mechanism Appendix 4: 2023 EPS Sensitivities

22 Endnotes are included in the Appendix. Protections Offered Under AB 1054 Appendix 5: 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 15+ 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 (~$3.7B)3 • If found prudent: no Wildfire Fund reimbursement required Physical Risk Mitigations1 Approved Wildfire Mitigation Plan (WMP) 2 Wildfire Safety Certification3

23 Endnotes are included in the Appendix. $140 - 165 per MWh Alternative New Renewable Baseload Generation $60 per MWh Diablo Canyon Cost Recovery People Planet Prosperity 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 Estimated Cost of Diablo Canyon Extension Compared to Alternative Non-GHG Emitting Technologies Appendix 6: SB 846 Diablo Canyon Legislation

24 Endnotes are included in the Appendix. 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 2019 2020 2021 2022 2023 7 48 120 300 650 2019 2020 2021 2022 2023 188 530 741 1,224 1,644 2019 2020 2021 2022 2023 241 899 1,209 1,351 1,426 2019 2020 2021 2022 2023 133 349 502 602 602 2019 2020 2021 2022 2023 627 1,005 1,313 1,424 1,424 2019-2023 ACTUALS1 STATIONS INSTALLED 1,424 CAMERAS INSTALLED 602 DEVICES INSTALLED 1,402 LINE MILES HARDENED 1,447 MILES COMPLETED 432 2023 TARGET DEVICES 75 MILES 350 LINE MILES 420 PROGRAM COMPLETED PROGRAM COMPLETED

25 Endnotes are included in the Appendix. 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 on July 6, 2021 • Second financing order became final, non-appealable on August 15, 2022 • $860M recovery bonds issued in November 2021 • $983M recovery bonds issued in November 2022 • Third securitization application to issue $1.38B recovery bonds filed August 10, 2023 • 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 and non-appealable as of 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 8: PG&E Utility Securitization Program

26 Endnotes are included in the Appendix. Changes from prior quarter noted in blue Regulatory Case/Filing Docket Status as of October 2023 Expected Milestones1 2023 GRC A.21-06-021 2023 GRC filed 6/30/21 Wildfire Self-Insurance Final Decision received 1/12/23 Proposed Decision and Alternate Proposed Decision 9/14/23 Phase 2 Testimony submitted 9/15/23 Final Decision Q4 2023 Phase 2 Proposed Decision April 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 Proposed Scope and Schedule issued 9/20/23 ACCAM Tier 2 Advice Letter filed 10/13/23 (4813-G/7046-E) 2021 WMCE A.21-09-008 Application filed 9/16/21 Settlement filed 1/18/23 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 Proposed Decision Q1 2024 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 Response to Revision Notice 9/27/23 Draft Decision due 11/14/23 2022 Safety Certificate 2022-SCs Submitted 9/14/22 Safety Certificate issued by OEIS 12/13/22 2023 Safety Certificate 2023-SCs No later than 90 days after submission Submission due 12/12/23 Minority Interest Sale in Pacific Generation LLC A.22-09-018 Filed 9/28/22 Schedule modified on 3/30/23 Proposed Decision within 90 days of 10/5/23 Wildfire and Gas Safety Costs A.23-06-008 Filed 6/15/23 Appendix 9: Regulatory Progress

27 Slide titles are hyperlinksSlide 3: Reaffirming Guidance 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 11, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share and Appendix 11, Exhibit E regarding non-GAAP financial measures. Slide 4: 2023: Mitigating Physical and Financial Risk 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 reflecting 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. 2% reduction calculated based on the prior year's operating and maintenance costs, excluding fuel costs. Reductions available for redeployment. 3. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 11, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share and Appendix 10, Exhibit E regarding non-GAAP financial measures. Slide 5: Building on Existing Layers of Protection 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 reflecting 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 6: 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 reflecting 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 9: 2023 Report Card 1. Defined by OEIS as a fire that caused at least one death, damaged over 500 structures, or burned over 5,000 acres. 2. 2% reduction calculated based on the prior year's operating and maintenance costs, excluding fuel costs. Reductions available for redeployment. 3. In accordance with AB 1054, $3.21 billion of fire risk mitigation capital expenditures will be excluded from the Utility's equity rate base. 4. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 10, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share and Appendix 10, Exhibit E regarding non-GAAP financial measures. 5. FFO/Debt is not calculated in accordance with GAAP. Because PG&E Corporation is not able to estimate the impact of specific line items, which have the potential to significantly impact the company’s FFO/Debt in future periods, it is not providing a reconciliation for the comparable future period FFO/Debt. Slide 10: Non-GAAP Core EPS Comparison 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 11, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share and Appendix 11, Exhibit E regarding non-GAAP financial measures. Appendix 10: Presentation Endnotes

28 Slide titles are hyperlinksSlide 12: Simple, Affordable Model 1. These numbers are illustrative approximations. 2. The Utility’s cost reduction strategies include increased efficiency and waste elimination driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to improve its capital-to-expense ratio, and an improved organizational design. Factors that may cause the Utility’s actual results to differ materially from its forecasts include whether the Utility can control its operating costs within the authorized levels of spending and timely recover its costs through rates; whether the Utility can achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons. 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 13: Value Proposition 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 11, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share and Appendix 11, Exhibit E regarding non-GAAP financial measures. 2. Pursuant to the Confirmation Order, PG&E Corporation agreed to not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings as defined in the Plan of Reorganization after the Plan of Reorganization effective date. Any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, PG&E Corporation’s results of operations, financial condition, cash requirements, contractual restrictions, and other factors that the Board of Directors may deem relevant. 3. CAGR is from 2022 through 2027. 4. 2% reduction calculated based on the prior year's operating and maintenance costs, excluding fuel costs. Reductions available for redeployment. 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. 5. FFO/Debt is not calculated in accordance with GAAP. Because PG&E Corporation is not able to estimate the impact of specific line items, which have the potential to significantly impact the company’s FFO/Debt in future periods, it is not providing a reconciliation for the comparable future period FFO/Debt. Appendix 10: Presentation Endnotes

29 Slide titles are hyperlinks Appendix 10: Presentation Endnotes Slide 18: Appendix 1: 2023 Factors Impacting Earnings 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 11, Exhibit A for a reconciliation of EPS on a GAAP basis to non-GAAP core earnings per share, Appendix 11, Exhibit C for PG&E Corporation’s 2023 Earnings Guidance, and Appendix 11, Exhibit E regarding non-GAAP financial measures. 2. 2023 equity earning rate base reflects 2020 GRC Final Decision, 2019 GT&S Final Decision, the April 15, 2021 FERC order denying the Utility's request for rehearing related to TO18, and TO20 Formula Rate, and 2023 GRC application including the September 2022 inflation update. 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. Base earnings plan assumes CPUC currently authorized return on equity and long- term capital structure across the enterprise. 4. Refer to Appendix 11, Exhibit C: PG&E Corporation's 2023 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 2023 impacts from changes in the federal tax code; and • All potentially dilutive securities were included in the calculation of Non-GAAP core EPS. 7. Unrecoverable interest expense includes PG&E Corporation long-term debt, Wildfire Fund contribution debt financing, and other interest above authorized. Slide 19: Appendix 2: CapEx And Rate Base 1. Upside opportunities of +$5 billion are not reflected in the CapEx or rate base ranges. 2. Low end of the range reflects authorized capital expenditures, including the full amount recoverable through a balancing account where applicable. High end of the range includes capital spend above authorized and reflects the spending forecast from the 2023 GRC application including the September 2022 inflation update. 3. On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Lakeside Building in Oakland, California, as modified. 4. CapEx includes AB 1054 qualified fire risk mitigation expenditures that will be excluded from the Utility's equity rate base. Slide 20: Appendix 3: Expected Recovery Of Wildfire-Related Costs 1. Balance represents wildfire-related costs approved in the 2020 GRC and recorded in the RTBA, WMBA, and VMBA, and amounts approved through subsequent advice letters. Slide 22: Appendix 5: 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. Slide 23: Appendix 6: 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 24: Appendix 7: Wildfire Mitigation Plan Progress 1. Actual data is from January 1, 2019 through September 30, 2023. Slide 26: Appendix 9: Regulatory Progress 1. Regulatory proceeding timelines reflect expected filing and decision time frames; actual timing may differ.

30 Appendix 11: 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 31-35 Exhibit B Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share ("EPS") Slides 36 Exhibit C PG&E Corporation's 2023 Earnings Guidance Slides 37-40 Exhibit D GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation Slides 41 Exhibit E Non-GAAP Financial Measures Slides 42

31 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 September 30, Nine Months Ended September 30, Earnings Earnings per Common Share Earnings Earnings per Common Share (in millions, except per share amounts) 2023 2022 2023 2022 2023 2022 2023 2022 PG&E Corporation’s Earnings/EPS on a GAAP basis $ 348 $ 456 $ 0.16 $ 0.21 $ 1,323 $ 1,287 $ 0.62 $ 0.60 Non-core items: (1) Amortization of Wildfire Fund contribution (2) 157 85 0.07 0.04 326 254 0.15 0.12 Bankruptcy and legal costs (3) 47 16 0.02 0.01 81 202 0.04 0.09 Fire Victim Trust tax benefit net of securitization (4) (46) 29 (0.02) 0.01 (185) (279) (0.09) (0.13) Investigation remedies (5) 3 5 — — 20 76 0.01 0.04 Prior period net regulatory impact (6) (6) (56) — (0.03) (17) (11) (0.01) (0.01) Strategic repositioning costs (7) 1 61 — 0.03 3 65 — 0.03 Wildfire-related costs, net of insurance (8) 9 12 — 0.01 73 190 0.03 0.09 PG&E Corporation’s Non-GAAP Core Earnings/EPS (9) $ 513 $ 608 $ 0.24 $ 0.29 $ 1,624 $ 1,783 $ 0.76 $ 0.84 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 2023 and 2022, except for certain costs that are not tax deductible. Earnings per Common Share is calculated based on diluted shares, except as noted. Amounts may not sum due to rounding. Third Quarter, 2023 vs. 2022 (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.

32 Third Quarter, 2023 vs. 2022 (in millions, except per share amounts) (3) Includes bankruptcy and legal costs associated with PG&E Corporation’s and the Utility’s Chapter 11 filing, including legal and other costs and exit financing costs, as shown below. (2) The Utility recorded costs of $219 million (before the tax impact of $62 million) and $453 million (before the tax impact of $127 million) during the three and nine months ended September 30, 2023, respectively, associated with the amortization of the Wildfire Fund asset and accretion of the related Wildfire Fund liability. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Legal and other costs $ 57 $ 86 Exit financing 9 26 Bankruptcy and legal costs (pre-tax) $ 66 $ 112 Tax impacts (19) (31) Bankruptcy and legal costs (post-tax) $ 47 $ 81 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

33 Third Quarter, 2023 vs. 2022 (in millions, except per share amounts) (4) Includes any earnings-impacting investment losses or gains, associated with investments related to the contributions to the Customer Credit Trust, 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 Net Operating Loss monetization, and tax benefits related to the Fire Victim Trust’s sale of PG&E Corporation common stock. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Wildfire OII disallowance and system enhancements $ 1 $ 2 Locate and mark OII system enhancements 1 2 Paradise restoration and rebuild 2 23 Investigation remedies (pre-tax) $ 4 $ 27 Tax impacts (1) (7) Investigation remedies (post-tax) $ 3 $ 20 (5) Includes costs associated with the CPUC’s OII into the 2017 Northern California Wildfires and 2018 Camp Fire, the system enhancements related to the locate and mark OII, and the restoration and rebuild costs for the town of Paradise, as shown below. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Rate neutral securitization charge $ 346 $ 908 Net gains related to Customer Credit Trust (1) (23) Fire Victim Trust tax benefit net of securitization (pre-tax) $ 345 $ 884 Tax impacts (96) (248) Tax benefits from Fire Victim Trust share sales (295) (822) Fire Victim Trust tax benefit net of securitization (post-tax) $ (46) $ (185) 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

34 Third Quarter, 2023 vs. 2022 (in millions, except per share amounts) (6) Includes 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. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Operating model $ 1 $ 4 Strategic repositioning costs (pre-tax) $ 1 $ 4 Tax impacts — (1) Strategic repositioning costs (post-tax) $ 1 $ 3 (7) The Utility recorded one-time costs related to repositioning PG&E Corporation’s and the Utility’s operating model, including their workforce. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 2011-2014 GT&S capital audit $ (8) $ (24) Prior period net regulatory impact (pre-tax) $ (8) $ (24) Tax impacts 2 7 Prior period net regulatory impact (post-tax) $ (6) $ (17) 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

35 Third Quarter, 2023 vs. 2022 (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 the PG&E Corporation and the Utility’s joint quarterly report on Form 10-Q for the quarter ended September 30, 2023. (8) Includes costs associated with the 2019 Kincade fire, 2020 Zogg fire, and 2021 Dixie fire, net of insurance, as shown below. (in millions) Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 2019 Kincade fire-related costs $ 2 $ 5 2020 Zogg fire-related costs 7 17 2020 Zogg fire-related insurance recoveries (2) (3) 2020 Zogg fire-related legal settlements — 50 2021 Dixie fire-related legal settlements 5 17 Wildfire-related costs, net of insurance (pre-tax) $ 12 $ 87 Tax impacts (3) (14) Wildfire-related costs, net of insurance (post-tax) $ 9 $ 73 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

36 All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 27.98% for 2023 and 2022. 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 increased O&M during the three months ended September 30, 2023, as a result of performing regular work that was delayed in the first half of 2023 due to storm response activity. During the nine months ended September 30, 2023, represents reduced spending for overhead expenses, operational expenses and support costs. (3) Represents redeployment of O&M savings into programs such as information technology system improvements and vehicle maintenance during the three and nine months ended September 30, 2023. (4) 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 and nine months ended September 30, 2023. (5) Represents lower uncollectible expense and other miscellaneous items during the three months ended September 30, 2023. During the nine months ended September 30, 2023, represents an increase for a combination of smaller items such as property taxes. Third Quarter 2023 vs. 2022 Year to Date 2023 vs. 2022 Earnings Earnings per Common Share Earnings Earnings per Common Share 2022 Non-GAAP Core Earnings/EPS (1) $ 608 $ 0.29 $ 1,783 $ 0.84 Operating and maintenance 2 (36) (0.02) 66 0.03 Redeployment 3 (24) (0.01) (66) (0.03) Timing 4 (60) (0.03) (85) (0.04) Other 5 24 0.01 (75) (0.04) 2023 Non-GAAP Core Earnings/EPS (1) $ 513 $ 0.24 $ 1,624 $ 0.76 Third Quarter, 2023 vs. 2022 (in millions, except per share amounts) Exhibit B: Key Drivers of PG&E Corporation's Non-GAAP Core Earnings per Common Share ("EPS")

37 2023 EPS Guidance Low High Estimated EPS on a GAAP basis ~ $ 0.99 ~ $ 1.08 Estimated Non-Core Items: (1) Amortization of Wildfire Fund contribution (2) ~ 0.19 ~ 0.19 Bankruptcy and legal costs (3) ~ 0.05 ~ 0.04 Fire Victim Trust tax benefit net of securitization (4) ~ (0.09) ~ (0.12) Investigation remedies (5) ~ 0.02 ~ 0.02 Prior period net regulatory impact (6) ~ (0.01) ~ (0.01) Strategic repositioning costs (7) ~ — ~ — Wildfire-related costs, net of insurance (8) ~ 0.03 ~ 0.03 Estimated EPS on a non-GAAP Core Earnings basis ~ $ 1.19 ~ $ 1.23 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 2023, 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. 2023 (in millions, pre-tax) Low guidance range High guidance range Amortization of Wildfire Fund contribution ~ $ 570 ~ $ 570 Amortization of Wildfire Fund contribution (pre-tax) ~ $ 570 ~ $ 570 Tax impacts ~ (159) ~ (159) Amortization of Wildfire Fund contribution (post-tax) ~ $ 411 ~ $ 411 (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 2023 Earnings Guidance

38 Exhibit E: PG&E Corporation's 2020 and 2021 Earnings Guidance (4) “Fire Victim Trust tax benefit net of securitization” includes the impact of rate neutral (SB 901) securitization and tax benefits related to the Fire Victim Trust. Impacts of the SB 901 securitization include 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. Fire Victim Trust tax benefits include tax benefits recognized upon the sale of shares of PG&E Corporation common stock by the Fire Victim Trust, which PG&E Corporation and the Utility have elected to treat as a grantor trust. Also included are any earnings-impacting investment losses or gains, associated with investments related to the contributions to the Customer Credit Trust. The low case includes tax benefits for the 180,000,000 shares of PG&E Corporation common stock sold in the aggregate by the Fire Victim Trust as of October 18, 2023, whereas the high case reflects an assumption that the Fire Victim Trust sells the remaining 67,743,590 shares during 2023. (3) “Bankruptcy and legal costs” consists of legal and other costs associated with PG&E Corporation’s and the Utility’s Chapter 11 filing, and exit financing costs. 2023 (in millions, pre-tax) Low guidance range High guidance range Legal and other costs ~ $ 105 ~ $ 90 Exit financing ~ 35 ~ 25 Bankruptcy and legal costs (pre-tax) ~ $ 140 ~ $ 115 Tax impacts ~ (39) ~ (32) Bankruptcy and legal costs (post-tax) ~ $ 101 ~ $ 83 2023 (in millions, pre-tax) Low guidance range High guidance range Rate neutral securitization charge ~ $ 910 ~ $ 1,210 Net gains related to Customer Credit Trust ~ (25) ~ (25) Fire Victim Trust tax benefit net of securitization (pre-tax) ~ $ 885 ~ $ 1,185 Tax impacts ~ (248) ~ (332) Tax benefits from Fire Victim Trust share sales ~ (820) ~ (1,105) Fire Victim Trust tax benefit net of securitization (post-tax) ~ $ (183) ~ $ (252) Exhibit C: PG&E Corporation's 2023 Earnings Guidance

39 (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 with the Safety and Enforcement Division’s investigation into the 2020 Zogg fire, and the locate and mark OII system enhancements. 2023 (in millions, pre-tax) Low guidance range High guidance range Paradise restoration and rebuild ~ $ 25 ~ $ 25 Wildfire OII disallowance and system enhancements ~ 15 ~ 15 2020 Zogg fire settlement ~ 5 ~ — Locate and mark OII system enhancements ~ 5 ~ 5 Investigation remedies (pre-tax) ~ $ 50 ~ $ 45 Tax impacts ~ (13) ~ (11) Investigation remedies (post-tax) ~ $ 37 ~ $ 34 2023 (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 2023 Earnings Guidance

40 (7) “Strategic repositioning costs” includes one-time costs related to repositioning PG&E Corporation’s and the Utility’s operating model, including their workforce, and costs associated with the potential sale of a minority interest in Pacific Generation LLC. Undefined, capitalized terms have the meanings set forth in the PG&E Corporation and the Utility’s joint quarterly report on Form 10-Q for the quarter ended September 30, 2023. (8) “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. 2023 (in millions, pre-tax) Low guidance range High guidance range Operating model ~ $ 5 ~ $ 5 Pacific Generation LLC minority interest sale ~ — ~ — Strategic repositioning costs (pre-tax) ~ $ 5 ~ $ 5 Tax impacts ~ (1) ~ (1) Strategic repositioning costs (post-tax) ~ $ 4 ~ $ 4 2023 (in millions, pre-tax) Low guidance range High guidance range 2019 Kincade fire-related costs ~ $ 15 ~ $ 10 2020 Zogg fire-related costs ~ 25 ~ 20 2020 Zogg fire-related insurance recoveries ~ (5) ~ (5) 2020 Zogg fire-related legal settlements ~ 50 ~ 50 2021 Dixie fire-related legal settlements ~ 15 ~ 15 Wildfire-related costs, net of insurance (pre-tax) ~ $ 100 ~ $ 90 Tax impacts ~ (28) ~ (25) Wildfire-related costs, net of insurance (post-tax) ~ $ 72 ~ $ 65 Exhibit C: PG&E Corporation's 2023 Earnings Guidance

41 Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2023 2022 2023 2022 PG&E Corporation’s Net Income on a GAAP basis $ 351 $ 459 $ 1,333 $ 1,297 Income tax benefit (416) (97) (1,099) (629) Other income, net (62) (118) (213) (246) Interest expense 682 525 1,924 1,355 Interest income (154) (43) (409) (70) Operating Income $ 401 $ 726 $ 1,536 $ 1,707 Depreciation, amortization, and decommissioning 811 1,002 2,885 2,915 Wildfire Fund expense 219 118 453 353 Fire Victim Trust tax benefit, net of securitization 345 40 884 40 Investigation remedies 4 2 27 96 Prior period net regulatory impact (8) — (24) 63 Strategic repositioning costs 1 5 4 5 Wildfire-related costs, net of insurance 12 156 87 229 PG&E Corporation’s Non-GAAP Adjusted EBITDA $ 1,785 $ 2,049 $ 5,852 $ 5,408 Third Quarter, 2023 vs. 2022 1. Amounts may not sum due to rounding. “Non-GAAP Adjusted EBITDA” is a non-GAAP financial measure. 2. 2022 Non-GAAP Adjusted EBITDA differs from what was reported on October 27, 2022 (removed Bankruptcy and legal costs from the calculation). Exhibit D: GAAP Net Income to Non-GAAP Adjusted EBITDA Reconciliation PG&E Corporation

42 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 (taken on a basic basis in the event of a GAAP loss and a diluted basis in the event of a GAAP gain). 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 2024-2026, 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