2024 FOURTH QUARTER AND FULL YEAR EARNINGS February 13, 2025 Delivering For Customers AND Investors 1

2 This presentation contains statements regarding PG&E Corporation’s and Pacific Gas and Electric Company’s (the “Utility”) future performance, including expectations, objectives, and forecasts about operating results (including 2025 non-GAAP core earnings), debt and equity issuances, rate base growth, capital expenditures, cash flow, cost savings, customer bills, wildfire risk mitigation, dividends, load growth, and regulatory developments. These statements and other statements that are not purely historical constitute forward-looking statements that are necessarily subject to various risks and uncertainties. Actual results may differ materially from those described in forward-looking statements. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Factors that could cause actual results to differ materially include, but are not limited to, risks and uncertainties associated with: • wildfires that have occurred or may occur in the Utility’s service area, including the extent of the Utility’s liability in connection with the 2019 Kincade fire, the 2021 Dixie fire, the 2022 Mosquito fire, and future wildfires; • the Utility’s ability to recover wildfire-related costs, including costs for the 2021 Dixie fire, from the Wildfire Fund (including the Utility’s maintenance of a valid safety certificate and whether the Wildfire Fund has sufficient remaining funds) and through the WEMA and FERC TO rate cases; • the Utility’s implementation of its wildfire mitigation programs, including PSPS, EPSS, situational awareness and response, the undergrounding initiative, and the programs’ effectiveness; • the Utility’s ability to safely and reliably operate, maintain, construct, and decommission its facilities; • changes in the electric power and natural gas industries driven by technological advancements and a decarbonized economy; • a cyber incident, cybersecurity breach, or physical attack; • severe weather events, extended drought, and climate change, particularly their impact on the likelihood and severity of wildfires; • the impact of legislative and regulatory developments, including those regarding wildfires, the environment, California’s clean energy goals, the nuclear industry, extended operations at Diablo Canyon nuclear power plant, regulation of utilities’ transactions with their affiliates, municipalization, privacy, and taxes; • the timing and outcome of FERC and CPUC proceedings, including regarding ratemaking, cost recovery, and other matters; • the outcome of self-reports, agency compliance reports, investigations, or other enforcement actions; • PG&E Corporation and the Utility’s substantial indebtedness, which may adversely affect their financial health and limit their operating flexibility; • the timing and outcome of PG&E Corporation’s and the Utility’s litigation, including securities class action claims, and wildfire-related litigation; • the Utility’s ability to manage its costs effectively, timely recover costs through rates, and achieve projected savings and the extent of excess unrecoverable costs; • the tax treatment of certain assets and liabilities, including whether PG&E Corporation or the Utility undergoes an “ownership change” that limits certain tax attributes; • the impact of growing distributed and renewable generation resources, and changing customer demand for its natural gas and electric services; • the Utility’s ability to construct necessary infrastructure and the extent of customer demand for new load; and • the other factors disclosed in PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2024, 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-K. Unless otherwise indicated, the statements in this presentation are made as of February 13, 2025. PG&E Corporation and the Utility undertake no obligation to update information contained herein. This presentation was attached to PG&E Corporation’s and the Utility’s joint Current Report on Form 8-K that was furnished to the SEC on February 13, 2025, and is also available on PG&E Corporation’s website at www.pgecorp.com. Forward-Looking Statements

3 Non-GAAP Core EPS1 31¢ Fourth Quarter 2024 Results …For Customers AND Investors Delivered On 2024… Endnotes are included in the Appendix 2026 - 2028 Guidance Delivered ► Delivered 11% Core EPS growth in 2024 ► Rebasing 2025 Core EPS growth; +10% off 2024 actual ► Dividend target 20% payout of non-GAAP Core EPS by 2028 ► Delivered 4% non-fuel O&M savings in 2024 ► Stabilizing residential bills; flat Jan 2025 vs. Jan 2024 Highlights $1.36 Full Year $1.48 - $1.52 2025 Up 10% 2024 - 2028 Equity Need Derisked At Least 9% +11%

4…Maximizing Customer Work, Building On Actual Results Simple, Affordable Model In Action1… Cost Performance and GRC At Least +9% $1.002 $1.10 At Least +9% Redeployment Redeployment Redeployment and Balance Sheet Strengthening Annual Guidance Headwinds and Tailwinds Storm Response and Interest Rates +11% Redeployment & Equity Issuance Endnotes are included in the Appendix 2021A 2022A 2023A 2024A 25F 26F 27F 28F +10% Cost of Capital At Least +9% +12% $1.23 $1.36 +10% EPS Growth3 Atmospheric Rivers

5…AND Getting Safer Every Day A Foundation Of Safety… Physical and Financial Safety Decarbonized Energy System Affordable and Resilient Energy

6 California Has Taken Action… …And Is Building An Industry Leading Model In 2019... What’s True Today Moving Forward AB 1054 was passed to: ✓ Build on provisions of 2018’s SB 901 ✓ Accelerate compensation for victims of utility-caused fires ✓ Move CA toward a safer, affordable, and reliable energy future ✓ Promote investment in wildfire risk reduction ✓ Wildfire Mitigation Plans ✓ Independent Safety Regulator ✓ Annual Safety Certification ✓ Presumption of Prudency ✓ Cost Recovery & Prudent Manager Standard1 ✓ Disallowance Cap2 ✓ Wildfire Fund for Claims Liquidity PG&E’s legislative priorities on wildfires are to build upon the original principles behind AB 1054: ▪ Promote investments which effectively mitigate wildfire risk ▪ Support financial health of the state’s utilities to the benefit of customers ▪ Provide appropriate assurances for investors given California’s no-fault strict liability standard Alice Reynolds, CPUC President If the utility acted prudently… these [property damage] costs are covered by ratepayers. Endnotes are included in the Appendix

7 Wildfire Mitigation Programs …Making Our Distribution And Transmission System Safer Every Day Layers Of Protection... Public Safety Power Shutoff (PSPS) Enhanced Powerline Safety Settings (EPSS) Wildfire Mitigation Programs ✓ 2,011 System Hardening miles completed** ✓ 875 Undergrounding miles completed** ✓ 1,541 Sectionalizing devices installed* ✓ 3.9M Trees removed* Enhanced Powerline Safety Settings (EPSS) ✓Deenergizes lines within 0.1 second upon detection of a fault/enabled on 100% of our distribution circuits in high fire threat districts and adjacent high fire risk areas Public Safety Power Shutoff (PSPS) ✓ In 2025, successfully executed 3 PSPS events; all included transmission lines ✓ In 2024, successfully executed 6 PSPS events; 4 included transmission lines Situational Awareness and Response* ✓ 635 Cameras Installed ✓ 1,582 Weather Stations Installed ✓ 24/7/365 HAWC Monitoring ✓Advanced Meteorology & Fire Models ✓Safety and Infrastructure Protection Teams Situational Awareness And Response * 2019 –2024 ** The 10,000-Mile Undergrounding Program started in 2021 and System Hardening totals include data starting in 2018

8…Moving Into Execution Phase PG&E Power Pyramid… Physical and Financial Safety Decarbonized Energy System Affordable and Resilient Energy

9…For Customers And California Story Of The Month: Enabling Affordable Load Growth… ✓ 15 customers, including hyperscalers and developers, intending to advance ✓ New pipeline projects online starting as early as 2026, driven by customer requested time to power ✓ Rule 30 application filed with CPUC in November 2024 *As of 2/4/2025 MWs Total 5,500 Intake & Preliminary Engineering 4,050 Final Engineering Construction 50 Data Center Pipeline* Estimated Long-Term Customer Savings: 1 GW = 1%-2% Electric Bill Reduction 1,400 2025 2030 2035 Data Center Pipeline Load Ramp Pipeline as of February 2025 Pipeline as of June 2024 5.5 GW 3.5 GW

10 Non-GAAP Core EPS1 Comparison... $1.36 7¢ (16¢) (3¢)(1¢) Full Year 2024 vs. 2023 Operating & Maintenance Savings 2024 Twelve Months 2023 Twelve Months Customer Capital Investment Redeployment 26¢ $1.23 Other - Miscellaneous Equity Issuance +11% …Delivered 2024 Guidance Endnotes are included in the Appendix Endnotes are included in the Appendix

11…Unchanged At $63B Five-Year Capital Plan… Plus At Least $5B Customer Beneficial Investment Opportunities3 Transportation Electrification Capacity Investments Transmission Upgrades: Data Centers and System Investments Incremental New Business Connections Hydro and Storage IT and Automation CPUC FERC ~10% CAGR 2023-2028 % Already Authorized1 93% 93% 86% 82% Weighted Average Rate Base ($B) $63B 2024-2028 CPUC FERC CapEx ($B)2 Endnotes are included in the Appendix 11 11 12 13 14 15 46 52 57 61 69 76 57 63 69 74 83 91 2023A 2024A 2025F 2026F 2027F 2028F 1.4 1.5 1.9 2.1 1.8 1.9 8.4 9.1 11 9.9 11.8 12.1 9.8 10.6 12.9 12.0 13.6 14.0 2023A 2024A 2025F 2026F 2027F 2028F

12…Supports Increased Customer Capital Investment Five-Year Financing Plan… (2½) (11) 11 3 0 10 20 30 40 50 60 70 Cash from Operations Dividends Paid Utility LT Debt Maturities Utility LT Debt Refinanced Utility LT Debt Issuance PG&E Corp. Senior Debt, Hybrid & Other Common Equity Issuance CapEx $50 $63 Amount ($billions) 2024 – 2028 Five-Year Financing Plan 14½ (2) Endnotes are included in the Appendix $4 1 $1½ 2025 Guidance (billions)

13…Supports Mid-Teens FFO/Debt1 Operating Cash Flow Growth… $Billions $3.7 $4.7 $8.0 $9 $0 $2 $4 $6 $8 $10 2022A 2023A 2024A 2025F Operating Cash Flow Growth Delivered 2023 GRC Catch-Up 2024 GRC Revenue 2022 WMCE Interim Rate Relief 2023 WGSC Interim Rate Relief 2023 Energy Cost Recovery Catch-Up Endnotes are included in the Appendix $9B

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

15…AND Deliver For Customers Our Ongoing Commitment To Stabilize Bills… Simple, Affordable Model Affordability Examples ▪ Optimizing our processes by utilizing our Lean Operating System ▪ Partnering with customer advocates on an alternative to commercial insurance ▪ Selling excess clean generation ▪ Working to reduce financing costs, including signing loan guarantee agreement with the Department of Energy Subtotal Enablers O&M cost reduction (non-fuel)2 Electric load growth3 Other (including efficient financing)4 Customer Capital Investment Customer Bills: At or Below Assumed Inflation 2% 1% - 3% 2% ~9% 5% - 7% 2% - 4% PLAN1 2% - 3%2% - 4% 2% 9% - 10% 6% - 9%1% - 3% 2% - 3% 2% - 4% 2 9% - 10% 6% - 9% 1% - 3% OPPORTUNITY1 1% - Endnotes are included in the Appendix

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

17…To Execute Our Plan Working With Policymakers And Stakeholders… 2025 10-Year Undergrounding Filing Jan 2024 2023 Safety Certificate Issued Mar 2024 2023 WGSC Interim Rate Relief Final Decision May 2024 Climate Adaptation Vulnerability Assessment Jul 2024 GRC “Capacity Phase” Final Decision Oct 2024 Cost of Capital: Phase 2 Approval Mar 2025 2026 Cost of Capital Filing Aug 2024 Oakland Headquarters Approval Sept 2024 2023 WMCE Interim Rate Relief Final Decision Dec 2024 2024 Safety Certificate Q2 2025 Energization Revised Cost Caps Final Decision May 2025 2027 GRC Filing Sept 2025 California’s 2025 Legislative Session Ends

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

19 $1.00 10% 12% 11% 10% 9% 9% 9% 21A 22A 23A 24A 25F 26F 27F 28F …Building Trust With Customers AND Investors Differentiated Growth And Regulatory Visibility… $B 2023 - 2040 0.8 0.9 1.4 1.6 2.4 PG&E 2023 PG&E 2024 PG&E 2028F 2023 Peer Avg 2023 Peer Top Decile Premium Growth Capital to Expense Ratio3 Load Growth Opportunity ~10% CAGR 4-Year Revenue Certainty 3-Year CoC Cycle w/ ROE Adjustment Mechanism GRC Phase 2 Energization Approval Constructive Legislation SB 884, SB 846, SB 410 CA Carbon Neutrality by 2045 Regulatory and Policy Environment Endnotes are included in the Appendix Rate Base Core EPS1 + DPS Growth 10% 57 63 69 74 83 91 23A 24A 25F 26F 27F 28F 2 2025 2030 2035 Pipeline as of February 2025 Pipeline as of June 2024 Data Center Pipeline Load Ramp Data Center Pipeline MWs Total 5,500 Intake & Preliminary Engineering 4,050 Final Engineering Construction 50 5.5 GW 3.5 GW 1,400

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

Appendix 1 Presentation Endnotes 21

22 Appendix 1: Presentation Endnotes Slide 3: Delivered On 2024 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. Slide 4: Simple, Affordable Model In Action 1. Gray line illustrates headwinds and tailwinds to delivering on annual non-GAAP core EPS guidance, as well as the impact of PG&E Corporation's and the Utility's responses to such developments. For instance, headwinds may include cost productivity below budget; unfavorable regulatory, legislative, or tax outcomes; interest expense; or assumptions or planning regarding the foregoing. Tailwinds may include cost productivity above budget; favorable regulatory, legislative, or tax outcomes; interest income; or assumptions or planning regarding the foregoing. Redeployment includes accelerating work, increasing the amount of work, and cost increases relative to the prior year. 2. Non-GAAP core EPS for the full year 2020 was $1.61 based on weighted average of approximately 1.257 billion shares outstanding. For illustrative purposes, 2020 non-GAAP core EPS has been recast using common shares outstanding on a fully diluted basis as of December 31, 2020 of approximately 2.124 billion shares. Non-GAAP core EPS for the full year 2021 was $1.00 per share on a fully diluted basis and $1.08 using a basic share count. The impact of dilution was $(0.08) per share. See Appendix 9, Exhibit A of the earnings presentation for the fourth quarter and full year 2021, available here, for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 9, Exhibit H regarding non-GAAP financial measures. 3. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit A for a reconciliation of EPS results on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 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 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. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Utility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. Slide 6: California Has Taken Action 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. Amount reflects 2024 electric transmission and distribution equity rate base. Slide 10: Non-GAAP Core EPS Comparison 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. Slide 11: Five-Year Capital Plan 1. Percentage already authorized for CPUC-jurisdictional rate base holds constant the 2026 revenue requirement for 2027 and 2028 and assumes FERC-jurisdictional rate base is equivalent to amounts requested in the formula rate through Transmission Owner rate proceedings for years 2024 through 2028. 2. Rate base point estimates reflect authorized capital expenditures from the 2023 GRC final decision, SB 410 incremental authorized spend in July 2024, Oakland headquarters Petition for Modification in August 2024 and other CPUC-jurisdictional approvals (including the full amount recoverable through a balancing account where applicable) and above authorized capital spend that will support the Utility's plan, including strategic capital investments in electrification, energization, undergrounding, and wildfire mitigation. 3. Investment opportunities of at least $5 billion are not reflected in the CapEx or rate base numbers. Slide 12: Five-Year Financing Plan 1. Includes funds to refinance long-term debt maturing in 2026. Slide 13: Operating Cash Flow Growth 1. FFO/Debt is not calculated in accordance with GAAP. Because PG&E Corporation is not able to estimate the impact of specific l ine items, which have the potential to significantly impact the company’s FFO/Debt in future periods, it is not providing a reconciliation for future period FFO/Debt. See Appendix 3, Exhibit E for a reconciliation of Operating income and Total debt on a GAAP basis to FFO/Debt and Appendix 3, Exhibit F regarding non-GAAP financial measures. Slide titles are hyperlinks

23 Appendix 1: Presentation Endnotes Slide titles are hyperlinks 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: Our Ongoing Commitment To Stabilize Bills 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. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Utility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 3. Expected drivers of forecasted electric load growth include electric vehicle adoption, data centers, and building electrification. 4. Factors that may cause the Utility’s actual results to differ materially from its forecasts include the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms; their ability to raise financing through securitization transactions; actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings; the supply and price of electricity, natural gas, and nuclear fuel ; its use of self-insurance for wildfire liability insurance; and the impact of any changes in federal or state tax laws, policies , regulations, or their interpretation, and PG&E Corporation’s and the Utility’s ability to obtain efficient tax treatment. Slide 16: O&M Cost Reduction Performance 1. These numbers are illustrative approximations and should not be interpreted as a guarantee of future performance. 2. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Utility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 3. Denoted amount is not material. 4. A higher discount rate used to measure the projected benefit costs at December 31, 2023 compared to December 31, 2022 resulted in lower pension and other post-retirement benefits service cost in the amount of $321 million. This decrease is embedded in 2023 net cost increases. Slide 18: Differentiated Performance 1. The Utility’s cost reduction strategies include increased efficiency driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to convert expenses to capital expenditures, and an improved organizational design. Factors that may cause the Utility’s actual results to differ materially from its forecasts include whether the Utility can control its operating costs within the authorized levels of spending and timely recover its costs through rates; whether the Utility can achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons. Non-fuel operating and maintenance costs is designed to represent the Utility’s operational efficiency. It excludes certain state-mandated programs where the Utility’s role is to facilitate achieving public policy goals regarding energy efficiency, the cost of which the Ut ility recovers; and expenses paid for using the statutory revenues associated with Diablo Canyon extended operations authorized by SB 846. This calculation also does not include balancing account deferrals; property taxes; non-core items; and other adjustments such as write-offs for canceled work including the Pacific Generation transaction. 2% reduction is calculated relative to the prior year. Reductions available for redeployment. 2. Expected drivers of forecasted electric load growth include electric vehicle adoption, data centers, and building electrification. 3. Factors that may cause customer bills to differ from forecast include risks and uncertainties associated with energy supply costs, emergency response costs, the timing and outcomes of regulatory proceedings, and customer energy usage. 4. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 5. CAGR is from 2023 through 2028. 6. FFO/Debt is not calculated in accordance with GAAP. See Appendix 3, Exhibit E for a reconciliation of Operating income and Total debt on a GAAP basis to FFO/Debt and Appendix 3, Exhibit F regarding non-GAAP financial measures.

24 Appendix 1: Presentation Endnotes Slide titles are hyperlinks Slide 19: Differentiated Growth And Regulatory Visibility 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibits A and C for reconciliations of EPS results and guidance, respectively, on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F 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. Represents Capital expenditures divided by Operating and maintenance, as disclosed in the applicable Annual Report on Form 10-K. Slide 26: Appendix 2: 2025 Factors Impacting Earnings 1. Non-GAAP core EPS is not calculated in accordance with GAAP. See Appendix 3, Exhibit C for a reconciliation of EPS guidance on a GAAP basis to non-GAAP core earnings per share and Appendix 3, Exhibit F regarding non-GAAP financial measures. 2. 2025 equity earning rate base reflects 2023 GRC final decision and the April 15, 2021 FERC order denying the Utility's request for rehearing related to TO18, TO19, and TO20 formula rates. 3. The capital structure of an investor-owned utility is the proportional authorization of shareholders’ equity and debt that comprise a company’s long-range financing or its capitalization. The CPUC currently authorized capital structure is comprised of 47.5% long-term debt, 0.5% preferred equity, and 52% common equity. 4. Refer to Appendix 3, Exhibit C: PG&E Corporation's 2025 Earnings Guidance. 5. Cash amounts for non-core items are after tax, directional, and subject to change. 6. Non-GAAP core earnings assumptions include no 2025 impacts from changes in the federal tax code. 7. Unrecoverable net interest includes PG&E Corporation long-term debt, Wildfire Fund contribution debt financing, and other interest above authorized, netted against the Utility’s balancing account interest. Slide 28: Appendix 2: Existing Construct In California Offers Sector-Leading Financial Protection 1. Prior to the enactment of AB 1054, utilities bore the burden of proving that their conduct was reasonable in order to obtain recovery of costs through rates. AB 1054 changed the standard so that the conduct of a utility is deemed reasonable unless a party to the proceeding creates a serious doubt as to the reasonableness of the utility’s conduct. Reasonable conduct is not limited to the optimum practice, method, or act to the exclusion of others, but rather encompasses a spectrum of possible practices, methods, or acts consistent with utility system needs, the interest of the ratepayers, and the requirements of governmental agencies of competent jurisdiction. 2. For fires in any calendar year. 3. Cap does not apply if Utility found to have acted with conscious or willful disregard of the rights and safety of others. Amount reflects 2024 electric transmission and distribution equity rate base. Slide 29: Appendix 2: SB 846 Diablo Canyon Legislation 1. The pre-extension period extends through the scheduled retirement dates of November 2024 and August 2025 for Units 1 and 2, respectively. 2. The extension period covers the additional 5-year life for each Unit.

Appendix 2 Supplemental Earnings Materials 25

26 2025 Factors Impacting Earnings Endnotes are included in the Appendix $1.48 - $1.52 Non-GAAP Core EPS1 2024 – 2028 Equity Need Complete Key Ranges Weighted Average Rate Base2 CPUC $57B FERC $12B Total Rate Base $69B Equity Ratio:3 52% Return on Equity: 10.28% Non-Core Items4 Key Factors Affecting Non-GAAP Core Earnings6 ($ millions after tax) Estimated non-core items guidance $360 - $400 Non-core items cash portion5 $300 ($ millions after tax) Unrecoverable net interest7 $350 - $400 Other earnings factors including AFUDC equity, incentive revenues, tax benefits, and cost savings, net of below-the-line costs

27 Expected Recovery Of Wildfire-Related Costs Recovery Outstanding By Year 1.1 1.4 1.4 1.4 1.4 2.6 1.1 0.5 0.3 0.9 0.8 0.5 4.6 3.3 2.4 1.7 1.4 0 1 2 3 4 5 Dec 23A Dec 24A Dec 25F Dec 26F Dec 27F Approved Pending Yet To Be Filed Total Amount ($billions) $0.8 Approved Recovery Status as of December 31, 2024 $1.1B Pending $1.4B Yet To Be Filed $3.3B Total 2022 WMCE $42M 2023 WMCE $869M 2023 WGSC $152M