VG 10-K & 10-Q changes, risk factors and insider trading

OurFor our projects that have yet to achieve COD, our ability to sell LNG commissioning cargos depends on our ability to successfully market, produce, load and, in some cases, deliver commissioning cargos during the commissioning of each of our projects prior to achieving COD. Although we have generated proceeds from the sales of commissioning cargos at the Calcasieu Project since thefrom first quarter of 2022 until COD was achieved in April 2025, and also at the Plaquemines Project since January 2025, prior to the relevant COD, such sales of commissioning cargos are limited in durationduration, and subject to a number of material uncertainties and risks. In addition, weWe are obligated to cease sales of commissioning cargos once the relevant COD occurs. The duration of the commissioning period at the Calcasieu Project, which has beenwas extended by a force majeure event, and the amount of proceeds we have generated from the sales of commissioning cargos from the Calcasieu Project toand datealso from the Plaquemines Project, may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any futureof periodour for the Calcasieu Projectprojects or expansions thereof for any offuture our other projects, including bolt-on expansions thereof.period. See —Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices and —Historical proceeds from commissioning cargo sales at the Calcasieu Project, which has had an extended commissioning period due to unanticipated challenges with equipment reliability that we are in the process of remediating and which began producing LNG in a high-price environment, may not be indicative of the duration of the commissioning period or the amount of proceeds for any future period or for any of our other projects,projects including bolt-onor expansions thereof.

Our ability to generate sales of LNG following COD at each ofproject ouror projectsexpansion thereof following COD, depends on our ability to successfully commence and maintain deliveries under our post-COD SPAs.SPAs Suchfor revenuessuch canproject beor furtherexpansion, supplementedand ifalso weon areour ableability to produce and sell LNG in excess of the nameplate capacity of oursuch projects.project or expansion. We will not generate any revenues or operating cash flow under our post-COD SPAs, or from sales to third parties of excess LNG that is produced above the nameplate capacity of our LNG projects, until we have achieved COD for the relevant project. ThereIn isaddition, nosuch guaranteerevenues thatmay be subject to increased volatility when compared to our long term post-COD SPAs if we willchoose achieveto suchenter CODsinto withinany shorter term SPAs or if we choose to sell any LNG in excess of the anticipatednameplate timeframes for achieving COD at anycapacity of our projects or at all, including ason a resultspot ofor risksshort describedterm elsewhere in these "Risk Factors", including —Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.basis.

As a result, there can be no assurance as to when we will commence deliveries under our post-COD SPAs, and therefore when, if at all, we will commence generating revenues and operating cash flows from our post-COD SPAs or from the sale of LNG produced in excess of nameplate capacity, if any, for the Calcasieu Project or any of our other projects, including bolt-on expansions thereof. In addition,Further, there can be no assurance that we will be able to produce excess LNG above the nameplate capacity of the facilities at our projects, either at our target level of excess LNG production or at all, nor, even if such excess LNG is produced, that we will be able to resell all of it to third party customers.

Our ability to monetize our other assets, including our pipelines, LNG tankers and regasification facility capacity depends on a variety of factors, including but not limited to market conditions in the natural gas and LNG industries, required regulatory and governmental approvals, and our ability to successfully market, produce, load and deliver commissioning cargos during the commissioning of each of our projects prior to achieving COD and our ability to generate sales of LNG following COD at each of our projects. Specifically, our ability to construct and successfully monetize our interstate and intrastate pipelines will depend, among other factors, on worldwide demand for LNG, as well as on our obtaining the necessary regulatory approvals for our projects currently under development. Additionally, while we expect several of our LNG tankers to service our single DPU post-COD SPA, our ability to monetize the remainder of our LNG tanker fleet will depend on the demand from LNG customers or, potentially, other charterers, as well as that from any future SPAs we may enter into where LNG is sold on a delivered basis, for the services of such LNG tankers. Our ability to monetize the regasification facility capacity we have secured through our agreements with Grain LNG and the Alexandroupolis LNG receiving terminals will depend on demand for both LNG and regasified natural gas from downstream customers in the UK and European markets.

In addition, as of December 31, 2024,2025, substantiallya allsignificant portion of the proceeds we have generated were proceeds generated from sales of commissioning cargos from the Calcasieu Project and the Plaquemines Project, and may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any future period for the Calcasieu Project or for any of our other projects,projects including bolt-onor expansions thereof, or of our future results of operations more generally.

Our limited operating history may limit your ability to evaluate our prospects because of our limited historical financial data, our unproven ability to maintain or increase our profitability and our positive cash flows and our limited experience in addressing issues that may affect our ability to manage the construction, operation or maintenance of liquefaction facilities and related assets. We face all of the risks commonly encountered by other growing businesses, including competition and the need for additional capital and personnel. As a result, any assessment you make about our current business and any predictions you make about our future success or viability may not be accurate. There is no assurance that our business will be successful over the long term.

Historical proceeds from commissioning cargo sales at the Calcasieu Project, which has had an extended commissioning period due to unanticipated challenges with equipment reliability that we are in the process of remediating and which began producing LNG in a high-price environment, may not be indicative of the duration of the commissioning period or the amount of proceeds for any future period or for any of our other projects,projects including bolt-onor expansions thereof.

The duration of the commissioning period and our ability to generate proceeds from the sale of commissioning cargos during such period is subject to significant risks and uncertainties relating to the development, construction and commissioning of our projects as discussed in these “Risk Factors.” In particular, it is both our intention and our obligation, under our post-COD SPAs, to undertake the construction of and complete our projects or phases thereof in a reasonable and prudent manner, which, depending on the circumstances, could extend or shorten the commissioning period for such projects or phases thereof during which we are able to generate such proceeds. Further, certain delays in the development of or construction of our projects,projects and any issues with the construction of our projects could delay or otherwise adversely impact our ability to generate such proceeds during the commissioning of the relevant projects. At any of our projects or phases thereof, if the commissioning of certain equipment or integrated facilities is delayed or if COD occurs earlier than expected, the duration of time when we are able to generate proceeds from the sale of commissioning cargos may be shortened, which could adversely impact the volume of LNG produced during commissioning and our ability to generate proceeds from the sale of commissioning cargos.

Historical proceeds from the sale of commissioning cargos at the Calcasieu Project, which has had an extended commissioning period due to unanticipated challenges with equipment reliability thatbefore weCOD areoccurred in theApril process of remediating,2025, may not be indicative of the duration of the commissioning period or the amount of proceeds for any future period or for any of our other projects,projects includingor bolt-on expansions thereof.expansions. Although we have included targeted COD dates for certain of our projects and phases thereof, there can be no assurance that COD will not occur earlier or later than such targets. If COD occurs earlier than expected for a particular project or phase thereof, it would adversely impact our ability to generate proceeds from the sale of commissioning cargos, which, subject to market conditions, may otherwise be more valuable than the revenues earned under our post-COD SPAs.

A key element of our business strategy is to generate proceeds from the sale of LNG at each of our projects during the construction and commissioning phases of our projects, prior to the relevant project achieving COD.

In addition to the duration of the commissioning period, our ability to generate such proceeds depends on our ability to negotiate sales during the construction and commissioning phases of each project. There is no assurance that we will be able to continue to successfully negotiate sales of such commissioning cargos on terms that are acceptable to us, or that we will be able to successfully market, produce, load and deliver such commissioning cargos, eithercargos from theour Calcasieu Project or any other project,projects in the future. In addition, because commissioning cargos are not sold under post-COD SPAs and are instead sold on varying terms, including in some instances on a forward basis, proceeds from such commissioning cargos may vary significantly depending on, among other factors, prices and market conditions in the international LNG markets, global LNG freight rates, and on the timing of when a contract for sale is executed. As such, the amount of any proceeds that we may generate from the sale of commissioning cargos and our profitability relating to such sales is largely dependent on the strength of international LNG markets, as primarily reflected in the spot price for LNG at the time a contract for sale of commissioning cargos is executed. Historically, the spot price for LNG has varied significantly, which has impacted the amount of proceeds wegenerated havefrom generated.the sales of commissioning cargos. Further, the proceeds that we generate during any given period of time may not necessarily correlate with the prevailing market prices for the corresponding period of time, given a variety of factors, including that we have and may continue to contract sales on a forward basis, at a pre-determined price.

As a result, we have experienced,experienced during the commissioning phase for the Calcasieu Project and the Plaquemines Project, and expect to continue to experience during the remainder of therespective commissioning phase,phase for our other future projects and expansions, significant volatility in the proceeds we have generated from the sales of commissioning cargos from the Calcasieu Project and the Plaquemines Project.cargos. Accordingly, the proceeds we have generated from such sales of commissioning cargos of the Calcasieu Project to datedate, may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any future period for the Calcasieu Project or for any of our other projects,projects includingor bolt-on expansions thereof.expansions. As a result, such proceeds, and also our operating results more generally, may vary significantly from one fiscal period to the next comparable fiscal period. Moreover, if we are not able to generate proceeds from the sale of commissioning cargos in the future that are comparable to such historical proceeds from the Calcasieu Project in the past,realized, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, and prospects.

Our ability to optimize sales of post-CODour LNG cargos is subject to significant uncertainty and volatility in proceeds generated from such sales.

Our business strategy includes applying cash proceeds from one project to decrease the financing required for future projects. Our strategy is to optimize sales of LNG produced following COD by committing certain nameplate capacity to long-term post-COD SPAs, with the aim of creating a base of stable cash flows, while reserving the rest of a project’s nameplate capacitycapacity, as well as its potential excess capacity, to sell on a short-, medium-, or long-term basis with the goal of optimizing pricing for such capacity and balancing profit, duration and risk.

Our ability to optimize sales of LNG cargos that are not otherwise committed will dependdepends on our ability to negotiate sales that meet our objective of balancing profit, duration and risk. There is no assurance that we will be able to successfully negotiate sales of such cargos on terms that are acceptable to us. In addition, because such cargos may be sold on varying terms, including in some instances on a forward basis, proceeds from such cargos may vary significantly from period-to-period and from project-to-project depending on, among other factors, prices and market conditions in the international LNG markets, domestic natural gas markets, global LNG freight rates, and on the timing of when a contract for sale is executed. Further, the amount of any proceeds that we may generate from such sales, and our profitability relating to such sales, is largely dependent on the strength of international LNG markets, as primarily reflected in the spot price for LNG at the time a contract for sale of such cargos is executed.executed, as well as the availability and pricing of feed gas. Historically, the spot price for LNG has varied significantly, as have domestic natural gas prices, and we expect thethese spot priceprices will continue to vary significantly in the future which will impact the amount of proceeds we generate from such sales. Further, we may at times contract such cargos on a forward basis and, as a result, such sales may be uncorrelated with movements in spot LNG prices.

We have not entered into SPAs with customers for the total expected nameplate capacity at Phase 2 of the CP2 Project, theor CP3other Project,future the Delta Project,projects or any potential bolt-on expansions, and our failure to enter into final and binding contracts for an adequate portion of, or to otherwise sell, the expected nameplate capacity of any of our projects, including any phases or expansions thereof, could impact our ability to take FID for such projects.

We are actively marketing a portion of the remaining expected nameplate capacity of Phase 2 of the CP2 Project to leading international oil and gas companies, national and multinational utilities and LNG portfolio trading companies. As of December 31, 2024,2025, Phase 2 of the CP2 Project has contracted to sell 9.251.0 mtpa of LNG under eighta 20-year SPAs.SPA. The obligation to make LNG available under thesethe post-COD SPAs commences from the occurrence of COD for Phase 12 of the CP2 Project. Additionally, we contracted through VG Commodities to sell 2.5 mtpa of LNG under 20-year Firm-start SPAs, which are expected to be transition to CP2 upon COD of Phase 2 of the CP2 Project.

As of this date, we have not entered into any SPAs for theany expectedof nameplateour capacityother forfuture theprojects potentialor bolt-on expansion capacity for the Plaquemines Project, the CP3 Project, and the Delta Projectexpansions and have not yet begun actively marketing the expected nameplate capacity for such developments.other future projects or expansions. While taking FID for a given project, including any phase or expansion thereof, is subject to numerous factors, we may elect to proceed with FID for Phase 2 of the CP2 Project, the CP3 Project, the Delta Project, any potential bolt-on expansions, or any other future projects, including any phases or expansions thereof, only after we execute binding SPAs for such projects, phases, or expansions, that cover a targeted portion of the applicable nameplate capacity that we consider adequate to support the development and financing of such project, phase, or expansion. Our inability to take FID for any future development project or any phase or expansion thereof may result in a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and, prospects.

We aim to develop and operate our LNG facilities to be capable of producing greater excess capacity,capacity at each of our projects, in mostsome cases atby leastas 30%much as 40% of their guaranteed nameplate capacity. Our ability to produce LNG in excess of the nameplate capacity at each of our projects is subject to significant risks and uncertainties relating to the development, construction and commissioning of our projects as discussed in these “Risk Factors.” Although we believe that our design and configuration will enable us to produce excess LNG without incurring material additional operating expenses or requiring additional capital investment, we may encounter additional, unforeseen costs, resulting in either operating expenses or capital investment, that make production of any excess LNG less economic or, potentially, uneconomic. Any increase in our incremental operating expenses or capital investments could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. As a result, there can be no assurance that we will be successful in producing any such excess LNG at any of our projects on a consistent and reliable basis, or at all.

To the extent we are unable to sell any such remainingexcess LNG, our revenues will be adversely impacted, and any such impact could be significant. In addition, we will likely still be required to pay certain of our operating expenses related to the anticipated production of such remainingexcess LNG (such as pipeline transportation costs incurred to transport natural gas for the production of such excess LNG) without generating any corresponding revenue. As a result, any such shortfall would also reduce our operating margins. Any of the foregoing could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

In addition, VG Commodities has contracted to resell at least 50% of the LNG generated post-COD by the Calcasieu Project in excess of itsthat project's nameplate capacity (subject to an annual cap at the option of the counterparty). Pursuant to such agreement, the counterparty is entitled to an assignment of VG Commodities’ rights under the applicable Intercompanyintercompany Excessexcess Capacitycapacity SPA in certain cases (including but not limited to when an event of default by VG Commodities has occurred and not been cured pursuant to such agreement with the counterparty). InVG addition,Commodities wehas also contracted to resell LNG generated by one or more of our other projects in excess of their respective nameplate capacities (excluding the 50% of the LNG generated by the Calcasieu Project) on a long-term basis. We may enter into similar arrangements related to the excess LNG at our other projects, including bolt-on expansions thereof, in the future.

Our ability to generate cash under our post-CODContracted SPAs and sales by VG Commodities is substantially dependent upon the performance by a limited number of our customers, and we could be materially and adversely affected if certain of these customers fail to perform their contractual obligations for any reason.

We currently have and expect to havecontinue having a limited number of customers to whom we sell LNG onunder aour post-CODContracted basis.SPAs and sales by VG Commodities. For example, as of December 31, 2024,2025, we have executed 39.2547.0 mtpa of post-COD SPAs and Firm-start SPAs with 2024 customers with respect to LNG from our projects, of which 37.4545.2 mtpa is contracted underon a 20-year fixed price SPAsbasis and 1.8 mtpa is contracted on a short- and medium-term basis. For the year ended December 31, 2024,2025, approximately 72%50.0% of our revenue for the period from individual external customers was concentrated across three customers. Moreover, for the year ended December 31, 2024,2025, we had one customer which represented approximately 32%23% of our revenue for that same period.

Our post-COD and other SPAs typically require, and we expect our future SPAs will require, our customers to pay a fee equal to a fixed facilityliquefaction chargefee per MMBtu, plus an amount equal to, depending on the applicable SPA, 115% or more of the Henry Hub price for feed gas that covers the cost of feed gas and is intended to cover gas transportation costs and certain of our other operating expenses. As a result, any decrease in the price of feed gas may reduce our operating margins under our SPAs.

We also anticipate that certain post-CODContracted SPAs and certain sales by VG Commodities we enter into will include a fixed fee that will only be partially adjusted for inflation over the contract term. As a result, inflationary pressures over time will not be fully reflected in the prices we charge our customers under oursuch post-CODsale SPAs.agreements. At the same time, our operating expenses are likely to increase due to inflationary pressure. Any such increases may not be fully offset by any partial inflation adjustments under our post-CODContracted SPAs or certain sales by VG Commodities and, as a result, inflation may reduce our operating margins.

We depend upon third-party pipelines to provide gas delivery options to our projects and any other natural gas liquefaction and export facilities that we may decide to develop in the future. We have entered into several precedent and service agreements with interstate pipeline companies to provide the natural gas transportation to the CalcasieuCalcasieu, ProjectPlaquemines, and the Plaquemines Project. We have begun to contract for natural gas transportation requirements for the CP2 Project and are currently in negotiations with other gas transportation companies to provide further natural gas transportation requirements for the CP2 Project and the natural gas transportation requirements for the CP3 Project and the Delta Project.Projects. We will need to enter into and secure additional pipeline transportation capacity for theour CP2other Project,future the CP3 Project, the Delta Project,projects and potentialand bolt-on expansionsexpansions, for us to generate the expected nameplate and excess capacity of LNG at such projects.projects or expansions. There can be no assurance that we will be able to enter into the requisite agreements to secure natural gas transportation capacity for our future projects and expansions on terms acceptable to us, or at all, which would impair our ability to fulfill our obligations under any SPAs. Even if we have entered into the requisite agreements for our projects, there can be no assurance we will be able to secure the necessary natural gas transportation capacity for each of our projects.

In addition, we depend on third-party natural gas suppliers to provide the feed gas required to generate the expected nameplate and excess capacity of LNG at our projects. We anticipate that we will establish and maintain a portfolio of natural gas supply agreements or contracts to meet our requirements, which we have commencedrequirements for the CalcasieuCalcasieu, ProjectPlaquemines and theCP2 Plaqueminesprojects, Project,and for our other future projects or expansions, but there can be no assurance that we will be successful in doing so on a long-term basis.

We also cannot control the regulatory and permitting approvals or third parties’ construction times, either with respect to capacity that has been secured or capacity that will be secured. If and when we need to replace one or more of our agreements with these interconnecting pipelines or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all, which would, in turn, impair our ability to fulfill our obligations under certain of our SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could prevent us from producing LNG or meeting our obligations under our SPAs and our ability to generate revenue would be adversely affected, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. In addition, if we are unable to deliver any contracted volume in full, our customers will generally be entitled to reimbursement of some or all costs and expenses for replacement LNG.

We havetrack includedand inmay thispresent Formfrom 10-Ktime to time certain calculationsmetrics ofthat total contracted revenue as anare illustrative metricand reflectingnot revenueindependently thatverified couldby any third party. Such metrics may be generated under our post-COD SPAs as of a particular date for the remaining term of all such post-COD SPAs. These calculations are based on certaina assumptions as described in the definitionrange of “totalassumptions, contractedsuch revenue” included under Glossary of Key Terms of this Form 10-K. Those assumptions include, among others,as the development, completion and commissioning of each of the relevant projects (including obtaining any required regulatory approvals), estimated contracted volume for eachsuch project’s existing post-COD SPAs, assumed rate of inflation, and an assumed Henry Hub gas price per MMBtu.MMBtu, the occurrence of certain environmental conditions and the composition of feed gas. Such assumptions are based upon our management’s assessment of market comparables and other indicative pricing in the market and will be affected by various factors, including actual inflation rates and Henry Hub gas prices during the term of the relevant SPAs, performance by our customers under the applicable SPAs, as well as by the various risks and uncertainties relating to development, construction, commissioning and operation of each of our projects (including obtaining any required regulatory approvals) as described in this “Risk Factors” section. ForIf example,such actualmetrics inflationare ratesnot accurate representations of our business, if investors do not perceive such metrics to be accurate, or if we discover material inaccuracies with respect to these figures, investors may lose confidence in our metrics and actual Henry Hub gas prices during the term of the relevant SPAs will likely differ from the assumed rate of inflationbusiness and assumed Henry Hub gas price used in such calculation, and any such differenceswe could be material.subject Asto alegal result,claims, actualincluding revenuesecurities generatedclass underaction thoselawsuits, SPAsbusiness, willcontracts, likelyfinancial differcondition, fromoperating theresults, totalcash contractedflow, revenuefinancing includedrequirements, in this Form 10-K,liquidity and any such differencesprospects could be material.affected. InvestorsOur shouldmethodologies notfor placecalculating unduethese reliancemetrics onhave a number of limitations and may change over time, which could result in unexpected changes to our illustrativemetrics, calculations ofincluding the totalmetrics contractedwe revenue.publicly disclose.

We may not be successful in pursuing bolt-on expansion opportunities at our current or future projects, which would adversely impact our growth prospects.

A key element of our growth strategy is to increase the liquefaction capacity at certain of our current and future projects through bolt-on expansions that involve adding incremental liquefaction trains and certain related equipment to the relevant project. Our ability to pursue any such bolt-on expansion is subject to a number of risks and uncertainties and there can be no assurance that we will be able to complete all or some of our currently anticipated bolt-on expansion opportunities.

In particular, bolt-on expansion opportunities are subject to regulatory approval, and as of the date of this Form 10-K, we have only recently requestedsubmitted initiationapplications of the pre-filing process withto FERC and DOE for such bolt-on expansion opportunities with respect to the Plaquemines Expansion Project and we have not otherwise made any filings with the necessary regulators, including DOE or FERC, with respect to any suchother expansion opportunities at our current or future projects. Such regulatory approvals are subject to numerous risks and uncertainties as described under —Risks Relating to Regulation and Litigation, and there can be no assurance that we will be successful in obtaining any such regulatory approvals. In addition, we are evaluating contracting and optimal financing options for any bolt-on expansions as there can be no assurance our projects will generate sufficient cash proceeds to fund all of the expansion opportunities we have identified at our current and future projects. Further, any bolt-on expansionexpansions will require sufficient additional natural gas supply at the relevant project, and there can be no assurance we will be able to enter agreements for supply or transportation of the requisite natural gas on terms acceptable to us or at all.

Additionally, the development and construction of any bolt-on expansions at our current or future projects could have an adverse effect on the ongoing or future construction, commissioning or operations, as applicable, of the relevant projects. The simultaneous construction and subsequent commissioning of any bolt-on expansion opportunities at any project while such project is otherwise in construction, commissioning, or operating at full capacity, could subject us and our third-party contractors to additional safety risks, as well as additional costs related to the management of those safety hazards and additional required regulatory approvals. Any such additional safety or other measures and approvals could result in additional costs, could delay our plans for any such expansions, or could result in a smaller size of any potential bolt-on expansion opportunity.

If we are not successful in pursuing bolt-on expansion opportunities that we have identified at our projects, or if any such expansion opportunities are executed only at a smaller scale or on a delayed timeline, our growth would be adversely impacted. Any of the foregoing could have an adverse effect on our growth, financial condition, operating results, and cash flow.

Our results of operations have fluctuated on a quarterly basis in the past, and may continue to fluctuate in the future, due to a wide variety of factors, including but not limited to the volatility in pricing and the seasonal nature of demand for natural gas and LNG, third-party supply disruptions, price spread between European and Asian LNG indices, the availability of, and associated freight rates of, LNG tankers and temperature and weather conditions across the markets we supply, which can have an impact on the demand for energy and, consequently, LNG. Accordingly, fluctuations in revenue during quarters of high and low demand, respectivelyrespectively, could have a disproportionate effect on our results of operations for the entire year. ThusThus, comparisons of our results of operations across different fiscal quarters may not be accurate indicators of our future performance. Annual or quarterly comparisons of our results of operations may not be usefuluseful, and our results in any particular period will not necessarily be indicative of the results to be expected for any future period. While we believe that our results of operations and earnings potential should be analyzed on a longer term view due to the nature of our business, such fluctuations can adversely affect our business and results of operations.

Substantially all of our anticipatedrevenue revenueis, and we expect will becontinue to be, dependent upon our LNG projects, all of which are currently located in southern Louisiana. Due to our limited asset and geographic diversification, an adverse development at the terminal or pipeline for our projects (including, for example, natural or man-made disasters affecting Louisiana, or significant long-term equipment failures), or in the natural gas or LNG industry,industries, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

An element of our strategy is to support our LNG growth through targeted transactions in areas of the natural gas industry that relate to our natural gas liquefaction and export projects. We intend to continue to explore targeted investments and acquisitions in the natural gas industry that complement and strengthen our project portfolio and solidify access to, and transport for, natural gas molecules, and the ability to deliver LNG, at commercially attractive terms. For example, we have in the past acquired firm regasification facility capacity at the largest LNG regasification terminal in Europe, Grain LNG,terminals in the United Kingdom, which we expect will allow us to import 42 LNG cargos per year beginning, depending on the starting period, anytime between October 1, 2029 to April 1, 2030, toKingdom and until July 14, 2045 (except for the period from April 1, 2030 to September 30, 2030 when only 13 LNG cargos can be imported). Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, which is expected to begin on October 1, 2025. Our capacity will account for approximately 25% of the total terminal capacity at Alexandroupolis, or approximately 12 cargos annually.Greece. While we believe that these contracted regasification capacities will allow us to supply both LNG and regasified natural gas directly into the European market to current and future downstream customers and allow us to continue to grow our presence in the European markets, we cannot guarantee that demand for delivered LNG or regasified natural gas will be in line with our expectations.

Although we have obtained certain customary insurance coverage in respect of the CalcasieuCalcasieu, Project, the Plaquemines Project,Plaquemines, and the CP2 Projectprojects, and our LNG tankers, we do not currently maintain insurance with respect to most aspects of the development, construction or operation of our other projects. We expect to obtain insurance as required under our contracts and consistent with industry standards (subject to availability on commercially reasonable terms) to protect against certain construction, operating and other risks, but not all risks will be insured or are insurable (for example, losses as a result of force majeure, natural or man-made disasters, terrorist attacks or sabotage or environmental contamination may not be available at all or on commercially reasonable terms). However, there can be no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at commercially reasonable rates, or on the same or substantially similar terms as our existing insurance coverage or that the insurance proceeds will be adequate to cover the repair or replacement of equipment and materials, to cover lost revenues from our projects, or to compensate for any injuries or loss of life. Further, we use a captive insurance subsidiary to insure certain risk related to named windstorms and such coverage involves retaining certain risks that might otherwise be covered by traditional insurance. If certain operating risks occur, or if there is a total or partial loss of a project in the future, there can be no assurance that the proceeds of the applicable insurance policies will be adequate to cover lost revenues, increased expenses or the cost of repair or replacement. Additionally, in the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay claims. Any increases in the number or severity of claims or any such loss that is not covered by our insurance policies could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Before construction of any project begins, we and our contractors, including our EPC contractors, need to hire new on-site employees to manage the construction of each project. We have engaged an EPC contractor to meet some of the construction labor needs of the Plaquemines Project and Phase 1 of the CP2 Project. In addition, before any of our projects commences operations, we need to hire an entire staff to operate the applicable facility. As a result, we expect the number of our personnel and our related costs to continue increasing significantly as we grow. If we and our contractors, including EPC contractors, are not able to attract and retain qualified personnel, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and the accompanying notes thereto, included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K. In addition to historical consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs that involve significant risks and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to those differences include those discussed below and elsewhere in Item 1A.—Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this Form 10-K. Except for per MMBtu amounts, or as otherwise specified, dollar amounts presented within tables are stated in millions.

OurVGLNG Sources of Capital. In July 2024, VGLNG issued $1.5 billion of 7.000% senior secured notes maturing January 2030. In September 2024, VGLNG issued 3 million shares of 9.000% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock for gross proceeds of $3.0 billion. In early 2025, we completed our IPO, issuing and selling 70 million shares of our Class A common stock at a public offering price of $25.00 per share.share for total net proceeds of $1.7 billion. In connection with the IPO, we effectuated a 4,520.3317-for-one forward stock split of our Class A common stock, which has been retrospectively incorporated into this Form 10-K, as applicable.stock.

Sales of LNG during commissioning. We generally sell LNG produced during the commissioning phase of our projects.projects, Weprior aimto COD, on a forward spot or short-term contracted basis. Our ability to generate cash proceeds from the sale of LNG produced during the commissioning phase of each of our projects. Our ability to generate such cash proceeds,LNG, and the amount of any such cash proceeds, will dependdepends primarily on the duration of the commissioning phase for each of our projects, the volume of LNG that we are able to produce during the commissioning phase, our ability to negotiate sales of LNG produced during the commissioning phase, as well as the market price for LNG at the time of such sales.sales are executed. As a result, the amount of cash proceeds we are able to generate from suchthe salessale of commissioning cargosLNG will likely differ from period to period and from project to project, and such differences could be material.

Sales of LNGContracted post-COD of our projects.LNG. We aim to generate cash proceeds from the sale ofsell LNG producedunder afterpost CODCOD-SPAs forand eachFirm-start ofSPAs our projects underleveraging a combination of long-term 20-year post-CODContracted SPAs as well as short- and medium-term post-CODContracted SPAs to optimize the average fixed facilityliquefaction chargefee across our SPAs. Further, to the extent our projects generate excess capacity relative to the nameplate capacity, we expect to sell such excess capacity as described below. None of our projects have achieved COD as of the date of this Form 10-K. Our ability to generate cash proceeds from such sales,revenue, and the amount of any suchassociated cash proceeds that we are able to generate, will be contingent upon achieving COD at each of our projects, and will vary depending on the followingfixed keyliquefaction factors:fee under our Contracted SPAs, the variable commodity fee indexed to the Henry Hub price of gas, as well as the volume and sales prices of LNG produced in excess of committed sales under Contracted SPAs.

◦Sales of uncommitted and excess LNG. We intendsell toLNG marketproduced above our Contracted SPA commitments under short‑, medium‑, or long‑term arrangements, providing commercial and sell any uncommitted LNG and any excess capacity through our wholly owned subsidiary, VG Commodities, which manages our shipping business, providing the flexibility to optimize pricing for such sales.flexibility. Our ability to generate cash proceeds from such sales, and the amount of any such cash proceedsrevenue that we are able to generate, will depend primarily on the volume of LNG that has been contracted under post-COD SPAs and the amount of LNG that we are able to produce at any project in excess of the nameplate capacity, our ability to negotiate sales of such uncommittedcapacity and excess LNG, as well as the market price for LNG at the time of such sales or the terms of any SPA we are able to negotiate with respect to such sales.executed. As a result, the amount of revenue and cash proceeds we are able to generate from suchthe salessale of uncommitted and excess LNG, if any, will likely differ from period to period and from project to project, and such differences could be material.

Cost of feed gas. The direct costs of purchasing, transporting and converting natural gas to LNG for sale to our customers are the mainprimary component of our cost of sales. Under theour post-CODContracted SPAs and substantially all of theour commissioning cargoLNG sales that we have executed to date, our export customers pay a fixed facilityliquefaction chargefee (which includes a CPI-linked component) per MMBtu, plus a variable commodity chargefee per MMBtu, in an amount equal to, depending on the applicable SPA, 115% or more of the Henry Hub gas price, which is intended to cover the price of the feed gas and gas transportation costs, and is also intended to cover certain of our operating expenses and partially adjust for inflation. If we are successful in producing and selling excess LNG produced by our projects, we expect our cost of sales to increase as we will be required to purchase more feed gas to produce more LNG.

ProjectOperating costs and expenses.costs. We currently have five projects in various stages of development. We expect our development, construction and commissioning expenses for any particular project to increase significantly as we approach and commence the construction phase, and we expect these expenses will continue to be significant until the commissioning phase has been completed and the relevant project reaches its COD. Moreover, our project costs may be higher than we currently estimate due to many factors outside of our control, which could lead to higher development, construction and commissioning expenses for our projects. In addition, we expect to increase our project‑dedicated staff as we progress towards the commencement of construction of the CP2 Project, the CP3 Project and the Delta Project and when we subsequently commence operationoperations at our facilities. As a result, we anticipate that operating and maintenance expenses will increase significantly as we approachcontinue commissioning and operation of our projects (as was the case for the Calcasieu Project).projects. We outsource certain major equipment maintenance activities under long-terms service arrangements, but our various operating subsidiaries are responsible for performing day-to-day operations and maintenance work for our projects. See Item 1.—Business—Major Consultants and Contractors of this Form 10-K for more information. Once one of our projects has commencedcommence full commercial operations, we anticipate that the timing of the operating and maintenance costs under the long-term service arrangements for that project will be relatively predictable, subject to inflation, and will generally increase during periods in which regularly scheduled or other maintenance is performed.inflation. Increases in operating and maintenance expenses would impact our operating margins. Further, we anticipate that insurance premiums for LNG projects may increase due to losses and claims that have arisen or been experienced in respect of other unrelated projects in other regions, or losses and claims that are large enough to impact the broader insurance market even if an LNG project is not involved.

Effective tax rates and regulations. We utilize various tax incentive programs offered by the State of Louisiana offers,Louisiana, including the industrial tax exemption, to offset local and state taxes that would otherwise be payable. However, the industrial tax exemption will expire after two 5‑year periods, which would begin on the last day of the tax year in which the Calcasieu Project, the Plaquemines Project and the CP2 Project assets, as applicable, are placed in service from an accounting perspective, and afterwards ad valorem taxes may be levied against our properties. We anticipate similar tax exemptions will be available for theour CP3 Projectgreenfield and theexpansion Delta Project,projects, although any such exemptions may only be available at lower rates. The future rates at which any taxes (including ad valorem taxes, inventory taxes, franchise taxes and utility taxes) will be levied against us will impact our operating margins.

Inflation. Inflation remains a variable factor in the United States economy, and it may impact our operating margins and results of operations in the future. In particular, we anticipate that theour post-CODContracted SPAs and sales by VG Commodities that include a fixed facilityliquefaction charge and that we enter intofee will only be partially adjusted for inflation over the contract term, as is the case with certain of our existing post-CODContracted SPAs as described above.SPAs. In addition, we anticipate that our operating costs will experience inflationary pressure over time, and the commodity charge we charge our customers for recovery of these costs is based on the price of natural gas per MMBtu.time. We also expect to experience inflation with respect to the cost of equipment and personnel necessary to develop, construct and operate our projects. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors and Item 1A.—Risk Factors—Risks Relating to Our Business—We and our contractors, including our EPC contractors, may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us of this Form 10-K.

Seasonality. Seasonal weather can affect demand for LNG and accordingly can impact our ability to sell LNG during the commissioning of our facilities or onceafter our facilities achieve their respective CODs. We have already begun experiencing, and we expect to experiencecontinue forto our other projects,experience, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets. For example, temperature and weather in the markets we supply, as well as the amount of natural gas in storage in such markets, may affect both power demand and power generation mix, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar or wind, thus affecting the need for LNG. Further, slower-than-expected inventory withdrawal due to mild weather can decrease the demand for LNG. Conversely, extreme or extended cold conditions in the U.S. may temporarily reduce LNG export volumes as domestic demand increases, reflecting how extreme weather events may influence near-term U.S. natural gas supply-demand balances and our export scheduling flexibility. Other factors, including but not limited to the price spread between European and Asian LNG indices and the availability of LNG tankers and the routes they choose to take due to seasonal and other factors can also affect the price of LNG. As a result, our ability to generate cash proceeds from LNG sales on a spot basis or short-term basis, and to enter into new SPAs for the sale of LNG, may be impacted by such factors, which may in turn result in fluctuations in revenue during quarters of high and low demand, respectively, and could have a disproportionate effect on our results of operations. As such, our results of operations across different fiscal quarters may not be comparable or accurate indicators of our future performance. For more information on these risks, see Item 1A.—Risk Factors—Risks Relating to Our Business—Seasonal fluctuations will cause our business and results of operations to vary among quarters, which could adversely affect our business and results of operations of this Form 10-K.

Macroeconomic Trends. Macroeconomic conditions, such as high inflation and elevatedinflation, interest rates, tariffs and global trade policy continue to be sources of volatility and uncertainty for global economic activity, and may affect our project costs and operations, as discussed above. See Item 1A.—Risk Factors—Risks Relating to Our Business—Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty of this Form 10-K. Ongoing geopolitical conflicts in Ukraine, the Middle East, Venezuela and tensions in United States-China relations may drive further economic instability and inflationary pressures, as well as increase risks for the global flow of goods, including energy. In the case of the LNG market, these geopolitical conflicts have and may continue to impact the availability of materials required for the development of LNG projects, in addition to disrupting the supply of LNG, resulting in price volatility on non-SPA volumes. For additional information on historical net spread volatility see Item 1A.—Risk Factors—Risks Relating to Our Business—Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices of this Form 10-K. Historical proceeds from such sales at the Calcasieu Project, which has had an extended commissioning period due to unanticipated challenges with equipment reliability that we are in the process of remediating, may not be indicative of the duration of the commissioning period or the amount of proceeds for any future period or for any of our other projects including bolt-on expansions thereof.

General and administrative expense was $433 million for the year ended December 31, 2025, an $121 million, or 39%, increase from $312 million for the year ended December 31, 2024, a $88 million, or 39%, increase from $224 million during the year ended December 31, 2023.2024. This increase was primarily due to higherincreased personnel costs of $43$82 million due to an increase inhigher employee headcount, increasesas inwell promotionalas activitiesincreased non-personnel costs of $10$38 million,million andprimarily due to increases in externallegal servicesand ofother $6professional million.service fees, IT and insurance costs.

The condensed consolidated financial statements and the accompanying notes thereto, included in Item 1.—Financial Statements of this Form 10-Q, and discussion and analysis of our financial condition and results of operations should be read in conjunction with our Annual Report on Form 10-K filed with the SEC on March 2, 2026 (the “2025 Form 10-K.10-K“). In addition to historical condensed consolidated financial information, this Form 10-Q contains forward-looking statements that reflect our plans, estimates, and beliefs that involve significant risks and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to those differences include those discussed below and in the Cautionary Statement on Forward-Looking Statements in this Form 10-Q and elsewhere in Item 1A.—Risk Factors of our 2025 Form 10-K. As used herein, unless the context otherwise requires, references to the "Company," "we," "us," and "our" refer to Venture Global, Inc. and its consolidated subsidiaries. Except for per MMBtu amounts, or as otherwise specified, dollar amounts presented within tables are stated in millions.

Our Consolidated Financial Results.

(1) Includes fixed liquefaction fees and fees indexed to foreign gas markets, exclusive of an actual or implied commodity fee.

Our income from operations for the threesix months ended MarchJune 31,30, 2026 increased compared to the prior year primarily due to higher sales volumes atfrom ourthe Plaquemines Project as acommissioning resultactivities ofprogressed the continued ramp up ofand LNG production,production andramped up, as well as lower development costscosts, primarily at ourthe CP2 Project following its declarationdesignation as probable duringin 2025, after which the majority ofmost development costs were capitalized. These increases were partially offset by lower weighted average LNG sales prices,prices drivennet of feed gas costs, and higher net operating and maintenance expenses primarily associated with commissioning and the ramp up of LNG production at Plaquemines, partially offset by lower pricesrectification undercosts ourat Plaquemines Project LNG Commissioning Sales Agreements and lower prices under ourthe Calcasieu Project post-COD SPAs as compared to prices under its LNG Commissioning Sales Agreements, as well as higher costs of feed gas.Project.

Calcasieu Project. Our initial LNG export facility declared COD and commenced the sale of LNG to its customers under its post-COD SPAs on April 15, 2025. Prior to COD, the Calcasieu Projectproject sold LNG under LNG Commissioning Sales Agreements.

Plaquemines Project. Production and LNG sales of LNG from our second LNG export facility increasedcontinue duringto theramp periodup while physicalas construction and commissioning continued to advance.progress. In March 2026, the DOE approved our application to increase authorized exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa. Additionally,Also in March 2026, we submitted aan newadditional DOE export application to further increase the authorized export volumes to 35.0 mtpa.

CP2 Project. Construction of our third LNG export project remains ongoing. In March 2026, Phase 2 of the CP2 Project achieved FID and we obtained $8.6 billion inof additional project financing to fund theits development and construction of Phase 2 of the CP2 Project.construction. During the threesix months ended MarchJune 31,30, 2026, we incurred $2.9$6.1 billion of project costs, the majority of which were capitalized,costs primarily associatedrelated withto construction activities and purchasesequipment of equipment.purchases.

In February 2026, the CP2 Project executedentered ainto or increased contracted capacity under two 20-year post-COD SPASPAs for the delivery of 1.5a combined 2.0 mtpa from Phase 2 of the CP2 Project,2, increasing the total expected post-COD capacity under contractcontracted from 26.0 mtpa to 27.528.0 mtpa.

In 2026, VG Commodities has executed variousseveral new five-year LNG sales agreements totaling approximately 3.03.8 mtpa, further advancing our strategy of maintaining a diversified portfolio of short-short-, medium- and long-term LNG sales agreements to optimize pricing and manage risk across our portfolioasset of assets.portfolio.

In April 2026, we strengthened our financial position by redeeming, in full,•redeeming the CP Funding Redeemable Preferred Units, which carried a stated cash interestdistribution rate of 10%10.000% and various liquidity restrictions, using proceeds from the newly issued variable rate Calcasieu Funding TLB Facility. Additionally, we repaid, in full, the outstanding balance of the Calcasieu Pass Construction Term Loan, which was due in August 2026, with proceeds from the newly issued VGCP 2036 Notes.Facility;

Three months ended MarchJune 31,30, 2026 compared to three months ended MarchJune 31,30, 2025