Slides
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Venture Global THIRD QUARTER 2025 NOVEMBER 10, 2025
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LEGAL DISCLAIMER Forward-Looking Statements This presentation includes statements that may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 (as amended, the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934 (as amended, the “Exchange Act”). All statements, other than statements of historical facts, included herein are “forward-looking statements .” In some cases, forward-looking statements can be identified by terminology such as “may,” “might,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology . These forward-looking statements, which are subject to risks, uncertainties and assumptions about us, may include projections of our future financial performance, expectations regarding the permitting and regulatory filings, development, construction, commissioning and completion of our projects, expectations regarding sales of LNG cargos, estimates of the cost of our projects and schedule to construct and commission our projects, our anticipated growth strategies and anticipated trends impacting our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements, including : our potential inability to maintain profitability, maintain positive operating cash flow and ensure adequate liquidity in the future, including as a result of the significant uncertainty in our ability to generate proceeds and the amount of proceeds that will regularly be received from sales of commissioning cargos and excess cargos due to volatility and variability in the LNG markets; the impact of the price of natural gas, including potential decreases in the price of natural gas and its related impact on our ability to pay the cost of gas transportation, the payment of a premium by us for feed gas relative to the contractual price we charge our customers, or other impacts to the price of natural gas resulting from inflationary pressures; our need for significant additional capital to construct and complete some future projects, and our potential inability to secure such financing on acceptable terms, or at all; our potential inability to construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, including any of the bolt-on expansion opportunities which we have identified, and to produce LNG in excess of our nameplate capacity, which could limit our growth prospects, including as a result of delays in obtaining regulatory approvals or inability to obtain requisite regulatory approvals ; significant operational risks related to our natural gas liquefaction and export projects, including the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, any future projects we develop, our pipelines, our LNG tankers, and our regasification terminal usage rights; our potential inability to accurately estimate costs for our projects, and the risk that the construction and operations of natural gas pipelines and pipeline connections for our projects suffer cost overruns and delays related to obtaining regulatory approvals, development risks, labor costs, unavailability of skilled workers, operational hazards and other risks; potential delays in the construction of our projects beyond the estimated development periods; our potential inability to enter into the necessary contracts to construct the CP2 Project, or the CP3 Project on a timely basis or on terms that are acceptable to us; our potential inability to enter into post-COD SPAs with customers for, or to otherwise sell, an adequate portion of the total expected nameplate capacity at the CP2 Project, the CP3 Project or any future projects we develop; our dependence on our EPC and other contractors for the successful completion of our projects and delivery of our LNG tankers, including the potential inability of our contractors to perform their obligations under their contracts ; various economic and political factors, including opposition by environmental or other public interest groups, or the lack of local government and community support required for our projects, which could negatively affect the timing or overall development, construction and operation of our projects; the effects of FERC regulation on our interstate natural gas pipelines and their FERC gas tariffs; our potential inability to obtain, maintain or comply with necessary permits or approvals from governmental and regulatory agencies on which the construction of our projects depends, including as a result of opposition by environmental and other public interest groups; the risk that the natural gas liquefaction system and mid-scale design we utilize at our projects will not achieve the level of performance or other benefits that we anticipate ; potential additional risks arising from the duration of and the phased commissioning start-up of our projects; the potential risk that our customers or we may terminate our SPAs if certain conditions are not met or for other reasons; potential decreases in the price of natural gas and its related impact on our ability to pay the cost of gas transportation, the payment of a premium by us for feed gas relative to the contractual price we charge our customers, or other impacts to the price of natural gas resulting from inflationary pressures; the potential negative impacts of seasonal fluctuations on our business ; our current and potential involvement in disputes and legal proceedings, including the arbitrations and other proceedings currently pending against us and the possibility and magnitude of negative outcomes in any such dispute or proceeding and the potential impact thereof on our results of operations, liquidity and our existing contracts ; the risks related to the development and/or contracting for additional gas transportation capacity to support the operation and expansion capacity of our LNG projects; the risks related to the management and operation of our LNG tanker fleet and our future regasification terminal usage rights; the uncertainty regarding the future of international trade agreements and the United States’ position on international trade, including the effects of any current or future tariffs imposed by the U.S. and any current or future tariffs imposed by other countries, including China, on the U.S.; the potential effects of existing and future environmental and similar laws and governmental regulations on compliance costs, operating and/or construction costs and restrictions ; our indebtedness levels, and the fact that we may be able to incur substantially more indebtedness, which may increase the risks created by our substantial indebtedness . For more information on these and other factors that could cause our results to differ materially from expected results, please refer to the risks and uncertainties discussed in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 6, 2025, as such factors may be updated from time to time in our periodic filings with the SEC, which are accessible on the SEC’s website at www.sec.gov. The forward-looking statements included in this presentation are made only as of the date of this presentation, and we undertake no obligation to publicly update or review any forward-looking statement, whether as a result of new information, future developments or otherwise, except as required by law. The guidance in this presentation is only effective as of the date given, November 10, 2025. Distribution or reference of this deck following November 10, 2025, does not constitute Venture Global, Inc (the “Company”) updating guidance. 2
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LEGAL DISCLAIMER (CONT’D) Market and Industry Data Certain of the information contained herein concerning industry and market data, economic trends, market position and competitiveness is based upon or derived from industry and market data from independent industry publications, other publicly available information and other reports prepared by third parties retained by the Company. Although the Company believes that these sources are reliable, the Company has not independently verified and does not guarantee the accuracy or completeness of this information, nor have we ascertained the underlying economic assumptions relied upon therein. Use of Non-GAAP Financial Measures This presentation contains references to Consolidated Adjusted EBITDA, which is not required by, or presented in accordance with, GAAP. We believe Consolidated Adjusted EBITDA provides investors and other users of our consolidated financial statements with useful supplemental information to evaluate the financial performance of our business on an unleveraged basis, to enable comparison of our operating performance across periods. Consolidated Adjusted EBITDA also allows investors and other users of our financial statements to evaluate our operating performance in a manner that is consistent with management’s evaluation of financial and operating performance . We define Consolidated Adjusted EBITDA as net income attributable to common stockholders of Venture Global Inc., as determined in accordance with GAAP, adjusted to exclude net income attributable to non-controlling interests, income taxes, gain/loss on interest rate swaps, gain/loss on financing transactions, interest expense, net of capitalized interest, interest income, depreciation and amortization, stock-based compensation expense, gain/loss from changes in the fair value of forward natural gas supply contracts, and gain/loss from changes in exchange rates on foreign currency transactions . We believe the exclusion of these items enables investors and other users of our consolidated financial statements to assess our sequential and year-over-year performance and operating trends on a more comparable basis. The Company does not provide a reconciliation of forward-looking amounts of Consolidated Adjusted EBITDA, due to the inherent difficulty in forecasting and quantifying certain amounts that are necessary for such reconciliations . Many of the adjustments and exclusions used to calculate the projected Consolidated Adjusted EBITDA may vary significantly based on actual events, so the Company is not able to forecast on a GAAP basis with reasonable certainty all adjustments needed in order to provide a GAAP calculation of these projected amounts . The amounts of these adjustments may be material and, therefore, could result in the GAAP amount being materially different from (including materially less than) the projected non-GAAP measures. Certain Other Measures We sometimes present total contracted revenue, which we defined as the sum, for the remainder of the term for all of our post-COD SPAs then in effect, of (i) the volume weighted average of the fixed facility charge component for all such post-COD SPAs for each project or project phase, multiplied by the contracted volumes for all such post-COD SPAs for the applicable project or project phase, in each case adjusted for inflation (assuming that 17.5% of the fixed facility charge component increases by 2.5% annual inflation every year following the first full year after COD), and (ii) the lifting revenue that would be earned for all such post-COD SPAs, assuming, for illustrative purposes only, all volumes contracted under each such post-COD SPA are lifted at an assumed Henry Hub gas price per MMBtu of $4.00 per MMBtu, in each case using a conversion factor of MMBtu to mtpa of 52. Our total contracted revenue is illustrative only and is based on a number of important assumptions . For more information on these and other factors that could cause our results to differ materially from expected results, please refer to the risks and uncertainties discussed in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 6, 2025, as such factors may be updated from time to time in our periodic filings with the SEC, which are accessible on the SEC's website at www.sec.gov. 3
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TABLE OF CONTENTS Section Company Highlights 5 Project Updates 8 Industry Trends 16 Financial Performance 19 Appendix 23 4
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COMPANY HIGHLIGHTS | ON A MISSION TO PROVIDE LOW-COST ENERGY TO THE WORLD Key Takeaways Four FIDs in Six Years Production capacity of ~67 MTPA (1) in operation or under construction positions Venture Global to be the largest LNG producer in North America and one of the largest in the world #1 Projected contribution to long -term U.S. balance of trade (4) >$1Tn Cargos exported as of November 7, 2025 +680 Capital(3) raised since inception ~$84 Bn Long-term offtake contracts signed to date 45 MTPA Aug 2019 Jan 2022 May 2022 Mar 2023 Dec 2024 Apr 2025 Jul 2025 Calcasieu Pass Final Investment Decision Calcasieu Pass First LNG Plaquemines Phase I Final Investment Decision Plaquemines Phase II Final Investment Decision Plaquemines Phase I First LNG Calcasieu Pass Commercial Operations Date (COD) CP2 Phase I Final Investment Decision Notes: 1. Estimated FERC permitted production capacity at Calcasieu Pass, Plaquem ines, and CP2 Phase I & II 2. Bolt-on expansions are subject to regulato ry approval 3. Figure is inclusive of the recently closed Senior Secured Corporate Revolving Facility 4. Assumes at least $10 /MM Btu FOB LNG prices, 100 MT PA of capacity from Calcasieu Pass, Plaquemines, and CP2 including expansions, with greater than 20 years of operation Targeted total production capacity by 2030 from facilities in operation or under construction, including Calcasieu Pass, Plaquemines, CP2, and potential bolt -on expansions (2) ~100 MTPA 5 On-Time Execution consistently meeting construction and commissioning milestones across projects Predictable Performance proven by track record of delivering reliable capacity expansions and cash flow forecasts Global Energy Access expanding supply of low -cost U.S. LNG to enable energy affordability for developing nations Backed by strong government support
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COMPANY HIGHLIGHTS | THIRD QUARTER Recent Company Accomplishments & FY 2025 Guidance Notes: 1. Consolidated Adjusted EBITDA is a non-GAAP metric . For definition and further informatio n on our use of non-GAAP metrics, please refer to the "Legal Disclaimer" at the beginning of the presentation . For a reconciliation of Consolidated Adjusted EBITDA to net income attributable to com mon stockholders as its m ost com parable GAAP metric for each time period presented, please refer to the Appendix at the end of this presentation 2. The Company does not provide a reconciliation of forward -looking non-GAAP financial measures, due to the inherent difficulty in forecasting and quantifying certain amounts that are necessary for such reconciliations . For further informatio n on our use of non-GAAP metrics, please refer to the “Legal Disclaimer” at the beginning of the presentation . For further detail on the guidance presented, please refer to slide 21 of this presentation 3. Consolidated Adjusted EBITDA includes portions attributable to Non-Controlling Interests . For 2025, the Non-Controlling Interest share of Consolidated Adjusted EBITDA is projected to be $105MM - $115MM 4. Represents cargo s which departed from Venture Global facilities during the respective time periods listed above 5. Net income as used herein refers to net income attributable to common stockholders on our Condensed Consolidated Statements of Operatio ns Consolidated Adjusted EBITDA(1) Summary $1,525MM Third Quarter 2025 Consolidated Adjusted EBITDA(1) $6.35 - 6.50Bn Full year 2025 Consolidated Adjusted EBITDA(1), reduced from Q2 (2)(3) 382 - 386 Full year 2025 cargos exported, narrowed from Q2 (4) 6 Income from Operations ($MM) Consolidated Adjusted EBITDA(1) ($MM)Net Income (5) ($MM) Revenue ($MM) $926 $3,329 Q3 2024 Q3 2025 $189 $1,320 Q3 2024 Q3 2025 ($347) $429 Q3 2024 Q3 2025 $283 $1,525 Q3 2024 Q3 2025 The Quarter Delivered Exceptional Performance Across Key Metrics
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COMPANY HIGHLIGHTS | THIRD QUARTER (CONT’D) Compounding Milestones: Recent Company Accomplishments Record 100 Cargos Exported in Q3 2025 0 25 50 75 100 125 Q122 Q222 Q322 Q422 Q123 Q223 Q323 Q423 Q124 Q224 Q324 Q424 Q125 Q225 Q325 Calcasieu Pass Plaquemines 100 Cargos exported in the quarter (36 from Calcasieu Pass and 64 from Plaquemines), at the high end of the guidance range 500th Cargo exported from Calcasieu Pass on November 8th 34 of 36 trains at Plaquemines have now produced LNG and the transition from temporary power to permanent site power is ongoing 2 New Offtake Commitments signed totaling 1.5 MTPA including Naturgy of Spain (1.0 MTPA) and ATLANTIC – SEE LNG of Greece (0.5 MTPA) CP2 received U.S. Department of Energy final authorization for non-FTA LNG exports of 28 MTPA YTD Total Recordable Incident Rate across our projects was 0.17 vs. national average of 1.9 as of September 2025 Final Investment Decision for CP2 Phase 1 on July 28th including largest LNG project financing ever of $15.1 billion Raised $1.575 billion of financing associated with the Blackfin Pipeline joint venture, providing $889 million return of capital to Venture Global New $2 billion Senior Secured Corporate Revolving Credit Facility(1) closed, significantly enhancing corporate liquidity and flexibility 3 Offtake Commitments signed in July totaling 3.75 MTPA including PETRONAS (1.0 MTPA), SEFE (0.75 MPTA), and Eni (2.0 MTPA) Issued $4.0 billion of Plaquemines senior secured notes in July 7 Notes: 1. Closed subsequent to the end of Q3 2025 We Are Building What Industry Said Couldn’t Be Done: Faster, Lower-Cost LNG At Global Scale – And We’re Only Getting Started
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PROJECT UPDATES
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PROJECT UPDATES | CP2 Phase I Offsite Module Procurement & Development (% Complete)(1)(2) Construction Personnel on Site >3,500 Soil Stabilized 5.4M CY (88%) LNG Tanks 28% 9 Liquefaction Trains Completed 8 of 26 CP Express Pipe Delivered 100% Major Power Equipment Delivered 100% CP2 Key Figures 99.5 % Engineering complete $8.2 billion Total invested as of October 31 st $1.1 billion Total spent on Phase II as of October 31 st 98 % Permanent plant equipment procured Liquefaction Modules Under Construction Notes: 1. % complete offsite does not incorporate scheduled time allo tted to install, commission, and test equipment onsite 2. As of October 31, 2025 Phase 1 Construction Site Progress (% Complete) (1)(2) Liquefaction Modules Under Construction CP2 in Progress
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PROJECT UPDATES | CP2 COMPOUNDING VALUE Replicating Proven Design for Reduced Risk and Improved Economics CP2 capitalizes on a decade of innovation, execution discipline, and market momentum – delivering strong returns with reduced risks CP2 builds upon Plaquemines’ proven next -generation design and the Venture Global “design one, build many” model, enabling repeatable modular fabrication, optimized vendor sourcing, and reduced scope variability. Engineering and construction teams leverage prior execution data to minimize rework, streamline sequencing, manage project teams, and improve safety and efficiency Learning-Curve Advantage De-risked project scope supports tighter debt spreads and improves equity returns. Design redundancy, predictive maintenance, and integrated production monitoring raise project availability while lowering O&M costs per MTPA Financing and Reliability Shorter build cycle shrinks time from investment to cash generation, improving project NPV and IRR. Brownfield reuse of marine and utility infrastructure reduces capex intensity per MTPA and enhances schedule certainty Execution and Capital Efficiency LNG produced during construction and commissioning supports funding for commissioning and rectification work, helps address unforeseen budget increases, and rigorously tests, in a sequential format, the performance and reliability of our equipment. Extensive testing de -risks longer-term performance under our 20 -year SPAs Value Realization and Early Monetization CP2 is permitted to produce 28 MTPA and engineered to generate more than 30 MTPA of LNG on a run - rate basis. Long -term SPAs and the expected contribution from incremental VG controlled capacity underpin our FID financings and low -cost LNG. We expect VG controlled volumes, sold on a short to intermediate term basis, to generate premium returns relative to our long -term SPAs Excess Capacity Enhances Returns and Flexibility 10
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PROJECT UPDATES | CP2 VALUE PROPOSITION Execution Driving Long-Term EBITDA Growth and Superior Returns Illustrative CP2 Return Profile Notes: 1. Assumes leverage of 50% 2. Assuming average fixed liquefaction fee for co mmissioning cargos of $3.93 per M MBtu 3. Assuming 2030+ fixed liquefaction fee of $2.30/M MBtu on long -term SPAs Anticipate >30% annual ROE (1) after netting Pre-COD EBITDA from construction cost Construction and Commissioning Post COD Annual EBITDA $ in Bn Phase II 11 ~550 Cargos Capital Consolidated Adjusted EBITDA $28.5 billion to $29.5 billion total project cost including both Phases I & II $8 billion of commissioning EBITDA based on current forward curves(2) ~$21 billion of net project cost after applying Pre-COD Cargos EBITDA to project costs ~$2.1 billion annual EBITDA(3) from long-term SPAs assuming 17 to 19 MTPA of the 28 MTPA of permitted capacity contracted $1.9 billion to $3.1 billion of run-rate EBITDA from 9 to 11 MTPA of available production contracted on a short to medium term basis at $4/MMBtu or $6/MMBtu fixed liquefaction fees, respectively $4.0 billion to $5.2 billion of post-COD run-rate EBITDA Plant engineered to produce 30 MTPA annually on a combined Phase I and Phase II basis (not accounted for in illustrative economics) ($29) $8 $2 .1 $1.9 - $3.1 Project Costs / CapEx Pre - COD Cargos EBITDA Post - COD Contracted Cargos EBITDA Post - COD Available Cargos EBITDA Run-Rate / Post - C OD C ontracted C argos $2.1 Available C argos @ $4 1.9 Total $4.0 Run-Rate $2.1 Available C argos @ $6 3.1 Total $5.2 Total Project C osts $29.0 C ommissioning C argos (+) 8.0 Net Project Cost $21.0
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34 of 36 liquefaction trains are now available to produce LNG while operating on temporary power 84% of potential(2) Q4 2025 cargos contracted at a weighted average fixed liquefaction fee of $6.41/MMBtu Plaquemines is expected to achieve COD in two phases Targeting Phase I COD in Q4 2026 and Phase II COD in mid-2027 Plaquemines will undergo a rigorous commissioning and testing program ahead of achieving COD for each phase Cargo Forecast PROJECT UPDATES | PLAQUEMINES Overview Production Summary and Forecast Ramp up supported by 400MW of temporary site power,(3) progressing faster than expected 23827.2 Anticipate 27.2MTPA of peak run -rate production by year-end despite Power Island construction delays We expect 234-238 commissioning cargos in 2025, which is an improved midpoint from Q2 2025 view of 227 -240 Historical Guidance Summary Q3 2025 Exported Cargos Q3 & YTD Exported Cargos Weighted Avg. Fixed Liquefaction Fee(3) n.a. $6.79/MMBtu 58 58 59 64 0 - 6 0 - 6 0 - 5 58 - 64 58 - 64 59 - 64 64 – 15 30 45 60 Prior Guidance - Mar 2025 Prior Guidance - May 2025 Prior Guidance - Aug 2025 Actual Weighted Avg. Fixed Liquefaction Fee(3) n.a. $6.99/MMBtu 0 64 0 144 – 30 60 90 120 150 Q3 '24 Q3 '25 YTD '24 YTD '25 Notes: 1. Quarterly cargo forecasts are only predictions based on our current expectatio ns and projections about future events, including about our current and future levels of production and sales. The quantity of actual cargo s that will be loaded and sold is subject to various risks, uncertainties and assumptions related to , among other things, operational, commercial and regulato ry matters . There are important factors that could cause the quantity of our actual future cargo s to differ materially from the ranges presented in these forecasts . See “Fo rward-Looking Statements” on slide 2 of this presentation for further detail 2. Calculated based on number of cargo s sold relative to m aximum expected cargo sales for the period 3. Plaquemines has permitted and staged 400MW of temporary power at the facility, which has allo wed it to mitigate contractor power island constructio n delays 12 90 - 94 88 - 94 82 - 88 82 - 88 – 25 50 75 100 125 Q4 '25 Q1 '26 Q2 '26 Q3 '26
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PROJECT UPDATES | PLAQUEMINES (CONT’D) The ramp in Plaquemines production in 2025 should grow global LNG production and supply by 4% Plaquemines accounted for 82% of new global LNG production thus far in 2025 The growth of Plaquemines cargos is mitigating the impacts of surging European LNG demand, which is up over 30% year to date, helping to keep global LNG prices affordable Plaquemines Production Growth – Our LNG Kept Global Energy Affordable 13
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Q3 & YTD Exported Cargos Cargo Forecast (2) Notes: 1. Represents the volume weighted average of the fixed liq uefaction fees asso ciated with all cargo s contracted to date, excludes variable charges 2. Quarterly cargo forecasts are only predictions based on our current expectatio ns and projections about future events, including about our current and future levels of production and sales. The quantity of actual cargo s that will be loaded and sold is subject to various risks, uncertainties and assumptions related to , among other things, operational, commercial and regulato ry matters . There are important factors that could cause the quantity of our actual future cargo s to differ materially from the ranges presented in these forecasts . See “Fo rward-Looking Statements” on slide 2 of this presentation for further detail Overview Production Summary and Forecast Deliveries under long-term SPAs to offtakers continued as scheduled – 100% reliability 500th cargo exported last week Scheduled power island and pretreatment maintenance was completed during the quarter with no material impact on output, highlighting the advantages of redundancy within the project design Expect Q4 2025 range of cargos at 40, which is the high end of our previous expectations Plant operating at run-rate capacity of 11 MTPA with focused effort to achieve 12.4 MTPA over the next 2-3 years Weighted average liquefaction fee has been adjusted for arbitration reserves Weighted Avg. Fixed Liquefaction Fee(1) $6.67/MMBtu $1.76 /MMBtuHistorical Guidance Summary Q3 2025 Exported Cargos 35 35 36 36 0 - 2 0 - 2 0 - 1 35 - 37 35 - 37 36 - 37 36 – 10 20 30 40 50 Prior Guidance - Mar 2025 Prior Guidance - May 2025 Prior Guidance - Aug 2025 Actual Q4 2025 Contracted Cargos 2026 Contracted Cargos $2.14/MMBtu $1.93/MMBtu 31 36 107 108 – 20 40 60 80 100 Q3 '24 Q3 '25 YTD '24 YTD '25 Weighted Avg. Fixed Liquefaction Fee(1) $6.76/MMBtu $4.29 /MMBtu PROJECT UPDATES | CALCASIEU PASS Weighted Avg. Fixed Liquefaction Fee(1) Contracted Cargos Potential Excess Cargos 14 40 37 36 34 0 0 - 3 0 - 2 0 - 3 40 - 40 37 - 40 36 - 38 34 - 37 – 10 20 30 40 50 Q4 '25 Q1 '26 Q2 '26 Q3 '26
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PROJECT UPDATES | CALCASIEU PASS ARBITRATIONS Frequently Asked Questions Are the remaining four arbitrations similar to the first three? Four separate VGCP post -COD offtaker arbitration proceedings, each with their own panel of arbitrators, remain ongoing, each with their own schedule Do these arbitration proceedings impact other Venture Global Projects? No, the VGCP arbitration proceedings impose no liability on the separate Plaquemines LNG and CP2 LNG projects, which are distinct legal entities that are not parties to the disputes Does this change the strategy? No, Venture Global remains committed to developing its project pipeline, does not foresee any changes to the targeted COD timings that have been publicly disclosed, and expects to continue progressing multiple long-term SPAs What is the financial impact of the BP ruling and other arbitrations on your financial results? Accounting guidance requires application of “best estimated” award outcomes over 20 -year life of SPAs Non-cash $27 million revision to Q3 EBITDA to address the 04/15/2025 – 09/30/2025 impact Anticipate $14m - $15m per quarter prospectively subject to current estimates Is the BP LNG SPA different from the Shell LNG SPA? As previously disclosed, the SPAs for Shell and BP, which were derived from the industry -standard US Gulf Coast LNG SPAs, many of which are publicly available, are substantially similar As such, Venture Global was very surprised and disappointed by the BP tribunal’s decision, which we believe is completely inconsistent with the express terms of the contract What is the expected timing for decisions from the remaining arbitrations? We expect one other customer arbitration to be decided as soon as the end of 2025 The remaining four separate VGCP post -COD offtaker arbitration proceedings are not expected to be decided until 2026 at the earliest What is the combined remedies and damages sought by the remaining arbitrations? For the four additional pending arbitrations, the remedies sought by customers total $3.8Bn - $4.5Bn We believe these four disputes are subject to the relevant seller aggregate liability limitation under the post-COD SPA, which aggregate to $765 million What is the current status of arbitrations? In August, VGCP received a favorable decision in the arbitration proceeding with Shell Following this result, VGCP and another post-COD offtaker agreed to settle a separate arbitration proceeding, without any material impact to Venture Global or its affiliates In October, the tribunal in the VGCP-BP arbitration issued a partial final award, finding that VGCP had breached its obligations to notice COD in a timely manner What is the financial impact of the BP proceedings? The finding does not assess any quantum of damages or require VGCP to make any payment to BP BP has referenced damages in excess of $1Bn, but has not yet clearly identified or pleaded their case for a precise amount of direct damages The BP tribunal will proceed to determine remedies in a separate damages hearing. A schedule has not yet been provided, but we do not expect any resolution in the near term / next six months 15
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INDUSTRY TRENDS
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© Australian Bureau of Statistics, GeoNames, Microsoft, Navinfo, Open Places, OpenStreetMap, Overture Maps Fundation, TomTom, Zenrin Powered by Bing INDUSTRY TRENDS | LNG PRICES AND CARGO DESTINATIONS Notes: 1. So urce: ICE, as of November 4, 2025 2. Represents cargo s expo rted as of September 30, 2025; data per DOE records Forward LNG and Henry Hub Prices(1) ($ / MMBtu) $9.04 $8.55 $3.63 Cargo Sales by Region(2) VG Cargo Destinations Since Inception Cargos 1 Cargo 99 Cargos – 30 60 90 120 Q1 2022 Q2 2022 Q3 2022 Q4 2022 Q1 2023 Q2 2023 Q3 2023 Q4 2023 Q1 2024 Q2 2024 Q3 2024 Q4 2024 Q1 2025 Q2 2025 Q3 2025 EMEA Asia Americas 17
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Global disposable net income per capita to grow 70% from 2022 to 2050 (4) more than doubling the number of air conditioning units from 2025 to 2050 (5) Population to grow by nearly 2 billion people to 9.8 billion by 2050 (6) Natural gas produces 30 – 60% less CO 2 when combusted for power generation (3), versus other traditional sources of energy Natural gas generates energy 24/7 and can be turned on and off with relative ease, representing a reliable and dispatchable source of power Data center power demand, which requires reliable 24/7 energy, expected to increase by 165% by 2030 vs. 2023 levels, rising to 3 -4% of global power demand from 1 -2% today (7) Coal-to-Gas Switching and Decarbonization Grid Reliability and Renewables Global Economic and Population Growth AI Driven Data Center Demand Growth Notes: 1. Industry data per S&P 2025 LNG Outlook . 2. 5.0% Growth Case curve is outside the fram e given the scale of the graph (included for illustrative purposes) 3. EIA “Carbon Dioxide Emissio ns Coefficients” (released September 7, 2023). Natural gas produces 116.65 lbs of CO2 per million British Thermal Units (M MBtu), versus traditional alternatives including diesel and home heating fuel (Distillate Fuel Oil at 163.45 lbs CO2 per MM Btu), Lignite Coal (216.64 lbs CO2 per MM Btu), and Bituminous Coal (205.57 lbs CO2 per MM Btu) 4. EIA, “World Disposable Income per Capita by Region, Reference Case” (Oct-2023) 5. IEA 6. United Nations Department of Economic and So cial Affairs 7. Goldman Sachs, “Supply/demand update : Improving demand picture extends tightness through 2025 + sector read-acro ss” - 100 200 300 400 500 600 700 800 900 1,000 2024 2028 2032 2036 2040 2044 2048 2024A Demand: 409MTPA 2050E Demand: 720MTPA 2050E Demand: 882MTPA 2050E Demand: 1,454MTPA Japan, South Korea, UNV1 Europe North America Other Asia South America Middle East & North Africa Sub-Saharan Africa Other Total 3.0% Growth Case 5.0% Growth Case LNG Demand Outlook by Region(1) (MTPA) Rising LNG Demand Reflects Long-Term Trends INDUSTRY TRENDS | STRONG COMPETITVE POSITION IN THE EXPANDING LNG MARKET (2) 18
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FINANCIAL PERFORMANCE
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FINANCIAL PERFORMANCE | THIRD QUARTER 2025 Raised $1.575 billion through the financing of the Blackfin Pipeline, which provides capital for the completion of the project and an $889 million distribution to Venture Global Cash & Restricted Cash of $3.5 billion on September 30, 2025 Repaid $48 million of the Calcasieu Pass Construction Loan New $2 billion senior secured corporate revolving credit facility in November Results in Q3 2025 were impacted by $27 million of Calcasieu Pass arbitration reserve reflecting 5.5 months since COD through the end of Q3. We expect to take future reserves of $14-$15 million per quarter, which may change based on future developments in our arbitration proceedings or future settlements Summary of Results and Drivers ($MM) Consolidated Q3 Adjusted EBITDA Bridge(2) ($MM) 1. Net income as used herein refers to net income attributable to com mon stockholders on our Consolidated Statements of Operatio ns 2. Consolidated Adjusted EBITDA is a non-GAAP metric . For definition and further informatio n on our use of non-GAAP metrics, please refer to the "Legal Disclaimer" at the beginning of the presentation . For a reconciliation of Consolidated Adjusted EBITDA to net income attributable to com mon stockholders as its most comparable GAAP metric of each time period presented, please refer to the Appendix at the end of this presentation 3. Represents cargo s which departed Venture Global facilities during the respective time periods listed above 4. Represents volumes of LNG delivered to customers during the respective time periods listed above. Reflected in results of operations Key Q3 2025 and Recent Updates (2) (2) Notes: Consolidated YTD Adjusted EBITDA Bridge(2) ($MM) (2)(2) 20 $283 $1,891 ($645) ($102) ($22) $103 $17 $1,525 Q3 2024 LNG Sales Volumes LNG Sales Prices net of th e Cost of Feed Gas Operating an d Maintenance Expenses General and Administra tive Expenses Development Expenses Other Q3 2025 $1,416 $3,966 ($966) ($336) ($73) $219 $38 $4,264 YTD 2024 LNG Sales Volumes LNG Sales Prices net of th e Cost of Feed Gas Operating an d Maintenance Expenses General and Administra tive Expenses Development Expenses Other YTD 2025 Q3 2024 ∆ Q3 2025 YTD 2024 ∆ YTD 2025 Revenue $926 260% $3,329 $3,448 170% $9,324 Income from Operations 189 598% 1,320 1,169 194% 3,438 Net Income(1) (347) NA 429 604 98% 1,193 Consolidated Adjusted EBITDA(2) 283 439% 1,525 1,416 201% 4,264 LNG Cargos Exported(3) 31 223% 100 107 136% 252 LNG Volumes Exported (TBtu) 110 237% 372 384 144% 936 LNG Volumes Sold (TBtu)(4) 100 273% 373 373 149% 931
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FINANCIAL PERFORMANCE | FULL YEAR 2025 GUIDANCE Full Year 2025 Guidance Commentary and Key Drivers Innovating to Provide Low-Cost LNG to the World Reduced Consolidated Adjusted EBITDA (1)(2) guidance for Full Year 2025 to $6.35Bn - $6.50Bn, decreasing the low end and decreasing the high end from previous guidance given in July including an adjustment for an arbitration related reserve We currently assume a fixed liquefaction fee range of $4.50/MMBtu - $5.50/MMBtu (down $1/MMBtu) for our remaining unsold cargos in 2025 in support of our updated guidance, reflecting market forward prices and recently executed cargo sales +/- $1.00/MMBtu change in fixed liquefaction fees will now impact our Full Year 2025 Consolidated Adjusted EBITDA by $50MM - $60MM, as opposed to $230MM - $240MM previously We now expect to export 148 cargos from Calcasieu Pass and 234-238 cargos from Plaquemines in 2025 reflecting a seven cargo increase to the low end and a three cargo decrease to the high end of the previous guidance range Key drivers which could shift our guidance going forward include: Potential excess cargos from Calcasieu Pass Pace of ramp up and performance of Plaquemines liquefaction trains Domestic (Henry Hub) and International (TTF, JKM) pricing dynamics Future arbitral awards from pending arbitration proceedings 21 Notes: 1. Industry data per S&P 2025 LNG Outlook . 2. Consolidated Adjusted EBITDA is a non-GAAP metric . For definition and further informatio n on our use of non-GAAP metrics, please refer to the "Legal Disclaimer" at the beginning of the presentation . The Company does not provide a reconciliation of forward -looking non-GAAP financial measures, due to the inherent difficulty in forecasting and quantifying certain amounts that are necessary for such reconciliations 3. Consolidated Adjusted EBITDA includes portions attributable to Non-Controlling Interests . For 2025, the Non-Controlling Interest share of Consolidated Adjusted EBITDA is projected to be $105MM - $125MM Full Year 2025 Guidance As of Q2 2025 Δ As of Q3 2025 Consolidated Adjusted EBITDA(1)(2) $6.4Bn - $6.8Bn $(50)MM - $(300)MM $6.35Bn - $6.50Bn Consolidated Adjusted EBITDA (+/- $1/MMBtu)(1) $230MM - $240MM $(180)MM $50MM - $60MM Calcasieu Pass Cargos 144 - 149 +4 / -1 148 Plaquemines Cargos 227 - 240 +7 / -2 234 - 238
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FINANCIAL PERFORMANCE | EBITDA GUIDANCE BRIDGE Full Year 2025 Changes to EBITDA Guidance ($MM) Commentary and Key Drivers Updated guidance contemplates at $1.50/MMBtu reduction in fixed liquefaction fee spread across 40 available cargos in Q4 2025 Guidance also adjusted to account for a $27 million arbitration reserve in Q3 2025 and a $15 million reserve in Q4 2025 22 Executing at Pace to Meet Rising Global Energy Demand $6,400 - $6,800 $6,350 - $6,500 ($111) ($37) ($42) $5,000 $5,500 $6,000 $6,500 $7,000 Previous Guidance Fixed Liquefaction Fee Price Movement 2 DES Cargos Shifted to Q1'26 Arbitration Reserve Updated Guidance
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APPENDIX
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APPENDIX | DIRECT SALES AND SHIPPING Venture Global Shipping Fleet Revenue Recognition Considerations Revenue associated with cargos exported on a Free on Board (“FOB”) basis is generally recognized when the LNG vessel is loaded and unmoors from one of our facilities. Revenue associated with cargos exported on a Delivered Ex-Ship (“DES”), Delivered Place Unloaded (“DPU”) or other delivered basis is generally recognized upon delivery of the LNG at the vessel destination. Occasionally, revenue associated with a cargo we export from our LNG terminals in a reporting period under such DES, DPU or other delivery terms will be recognized by the Company in a subsequent reporting period due to the time required for the vessel to successfully travel to its destination and unload its cargo. For the quarter ended September 30, 2025, we recognized two DES cargos from our Plaquemines LNG facility on our owned or chartered LNG vessels that were originally exported in Q2 2025. Furthermore, we exported two separate cargos during Q3 2025 that will be delivered and recognized as revenue in the following quarter. We anticipate two DES ships loaded in Q4 2025 to be recognized in our 2026 financial results. Notes: 1. Expected delivery dates for Venture Iberia, Venture Cameron, Venture Manatee, and Venture Venice Ship Delivery Date Owned / Chartered Charter End 1. Venture Gator Jun-2024 Owned n.a. 2. Venture Bayou Jul-2024 Owned n.a. 3. Gaslog Savannah Aug-2024 Chartered 8/23/2026 4. Minerva Psara Sep-2024 Chartered 8/05/2027 5. Venture Acadia May-2025 Owned n.a. 6. Venture Creole Jul-2025 Owned n.a. 7. Venture Pelican Aug-2025 Owned n.a. 8. Venture Iberia (1) Nov-2025 Owned n.a. 9. Venture Cameron (1) Q1 2026 Owned n.a. 10. Venture Manatee (1) Q3 2026 Owned n.a. 11. Venture Venice (1) Q4 2026 Owned n.a. 24
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APPENDIX | SELECTED SIMPLIFIED ORGANIZATIONAL STRUCTURE(1) $4.8Bn Senior Secured Notes $0.9Bn Senior Secured Credit Facilities $0.6Bn Working Capital Facility $11.0Bn Senior Secured Notes Plaquemines LNG Pledgor, LLC Calcasieu Pass Pledgor, LLC Venture Global Calcasieu Pass, LLC (Calcasieu Pass LNG Facility Project Company) Calcasieu Pass Holdings, LLC Calcasieu Pass Funding, LLC ~77% Venture Global Plaquemines LNG, LLC (Plaquemines LNG Facility Project Company) $6.5Bn Senior Secured Notes $5.7Bn Senior Secured Credit Facilities $2.1Bn Working Capital Facility $3.0Bn Perpetual Preferred Equity Venture Global, Inc. (NYSE:VG) Venture Global LNG, Inc. Notes: (1) Simplified organizational chart that does not include all legal entities . All ownership is 100% of the existing common stock of each entity listed unless otherwise noted. Reflects balances as of September 30, 2025 (2) Closed subsequent to the end of Q3 2025 (3) Stonepeak holds ~23% of common units of Calcasieu Pass Holdings, LLC (4) Remaining 50% owned by WhiteWater Midstream Venture Global Midstream Holdings, LLC CP2 LNG Pledgor, LLC Venture Global CP2 LNG, LLC (CP2 LNG Facility Project Company) $11.3Bn Senior Secured Credit Facilities $0.9Bn Working Capital Facility Venture Global Commodities, LLC Venture Global CP2 LNG Holding, LLC $3.0Bn Phase I Equity Bridge Facility Stonepeak Equity Investment ~23%(3) 25 $1.7Bn Stonepeak Redeemable Preferred Equity Blackfin Pipeline Holdings, LLC $1,050MM Senior Secured Term Loan B $425MM Senior Secured Term Loan A $75MM Senior Secured Revolving Credit Facility ~50%(4) $2.0Bn(2) Corporate Revolving Credit Facility
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APPENDIX | CONSOLIDATED ADJUSTED EBITDA RECONCILIATION Notes: 1. Consolidated Adjusted EBITDA is a non-GAAP metric . For definition and further informatio n on our use of non-GAAP m etrics, please refer to the "Legal Disclaimer" at the beginning of the presentation 2. Changes in fair value of forward natural gas supply contracts Consolidated Adjusted EBITDA ($MM) – Quarterly(1) and YTD(1) The following table reconciles our Consolidated Adjusted EBITDA to U.S. GAAP results for the three months ended September 30, 2025, and 2024 The following table reconciles our Consolidated Adjusted EBITDA to U.S. GAAP results for the nine months ended September 30, 2025, and 2024 26 Three months ended September 30, 2025 2024 Net income (loss) attributable to common stockholders 429$ (347)$ Net income attributable to non-controlling interests 121 53 Income tax expense 87 (78) Loss on foreign currency transactions 4 - Loss on financing transactions 141 6 Loss on interest rate swaps 144 480 Interest expense, net 421 128 Interest income (27) (53) Income from Operations 1,320$ 189$ Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization 218 89 Stock based compensation expense 11 5 Loss from changes in fair value of other derivatives(2) (24) - Consolidated Adjusted EBITDA 1,525$ 283$ Nine months ended September 30, 2025 2024 Net income attributable to non-controlling interests 1,193$ 604$ Net income attributable to non-controlling interests 349 152 Income tax expense 354 189 Loss on foreign currency transactions 4 - Loss on financing transactions 204 14 (Gain) loss on interest rate swaps 448 (70) Interest expense, net 1,007 467 Interest income (121) (187) Income from Operations 3,438$ 1,169$ Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization 701 229 Stock based compensation expense 34 18 Loss from changes in fair value of other derivatives(2) 91 - Consolidated Adjusted EBITDA 4,264$ 1,416$
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Contacts Investor Contacts Ben Nolan ir@venturegloballng.com Media Contact Shaylyn Hynes press@venturegloballng.com 27