Venture Global, Inc.

Overview

Our Company

Venture Global is a long-term, low-cost provider of U.S. LNG sourced from resource rich North American natural gas basins. Our integrated assets span the LNG supply chain, including LNG production, natural gas transportation, shipping and regasification. Our innovative approach, which is both scalable and repeatable, allows us to bring low-cost LNG to a global market years faster than traditional LNG projects. We believe supplying this clean, affordable fuel promotes global energy security and diversification and is essential to meeting growing global energy demand.

Natural gas is a vital global resource that underpins economic development through the generation of reliable electricity. By cooling natural gas to -260°F, it is converted to LNG—reducing its volume to 1/600th of its original state for efficient transport by LNG tankers to international markets lacking domestic supply, displacing more carbon intensive sources of energy such as coal and oil. Venture Global’s modular, “design‑one, build‑many” approach enables faster, more cost-efficient construction and the rapid deployment of productive assets compared with traditional LNG projects, forming the foundation of both our operating platform and development strategy.

Liquefaction and Export Projects

We are operating, constructing, and developing multiple LNG export projects in Louisiana. Each project is designed to include an LNG facility and associated pipeline systems to deliver natural gas into the LNG facility through interconnected interstate and intrastate pipelines. We currently own all or a majority interest in each of our LNG projects providing full managerial control and operational flexibility.

Our “design‑one, build‑many” approach allows us to pursue bolt-on expansions efficiently across existing sites. These bolt-on expansion projects are designed to leverage existing plant infrastructure and equipment to reduce per tonne capital costs relative to new, or greenfield, developments, although they may require, among other things, incremental natural gas supply arrangements, pipelines, and pipeline transportation capacity for the applicable project in order to support the additional capacity of such bolt-on expansions.

The "expected" annualized production capacity for each facility represents anticipated sustainable post-COD production levels under normal operating conditions (e.g., typical day-to-day temperatures, pressure, humidity, reliability, gas supply and standard operating parameters). Our facilities may temporarily achieve higher throughput—i.e., the maximum technical output—under optimal or "peak" conditions (e.g., cooler ambient temperatures, peak equipment efficiency, ideal feed-gas composition and minimal downtime). Actual performance will vary over time and depends on a multitude of factors. The "currently permitted" capacity reflects the volumes authorized to date by one or more relevant regulatory agencies. In certain cases, these amounts represent the lower end of our fully permitted range—such as where FERC authorization has been granted but DOE approval for exports to Non-FTA Nations remains pending. Accordingly, currently permitted capacities may increase as additional authorizations are received.

The following table summarizes our current LNG export projects, together with their stages of advancement and permitted capacities.

(1) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the Plaquemines Project from 27.2 mtpa to 35.0 mtpa. We have a pending application with DOE to increase the authorized exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa, and we intend to submit another DOE export application in the first half of 2026 to increase the authorized export volumes to 35.0 mtpa. See—Governmental Regulationof this Item 1.

(2) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See—Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(3) In November 2025, we filed applications with the FERC and DOE proposing a 31.0 mtpa expansion of the Plaquemines Project (the “Plaquemines Expansion Project”). The Plaquemines Expansion Project replaces the Delta Project which we withdrew from the FERC pre-filing process on June 10, 2025, as described in—Governmental Regulation of this Item 1.

(4) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the CP2 Project to 35.0 mtpa. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations 35.0 mtpa. Both the FERC and DOE Non-FTA Nations authorizations are subject to on-going appeals. See—Governmental Regulation of this Item 1.

(5) We intend to file applications with the FERC and DOE proposing a 11.7 mtpa expansion of the CP2 Project (the "CP2 Expansion Project") in the first half of 2026. See—Governmental Regulation of this Item 1.

(6) As of the date of this Form 10-K, no FERC and no DOE filings have been made and none of the necessary approvals for the CP3 Project have been obtained.

Our Operational Strategy

Our primary goal is to become one of the lowest-cost providers of LNG in the industry. Our operations emphasize:

•Use of a proven liquefaction system with a standardized configuration across all facilities;

•Leveraging scale and standardization across our projects to optimize performance and reduce redundancy;

•Data-driven production optimization and reliability initiatives;

•Vertical integration through shipping and regasification in key import markets;

•Long-term natural gas supply and transportation agreements with domestic producers; and

•Comprehensive health, safety and environmental programs.

We believe our unique electric motor driven modular configuration and our owner-led construction model enable us to produce low‑cost, reliable LNG for customers while maintaining flexibility and speed in project execution.

LNG produced by our facilities is sold to our customers on either a FOB, DPU or DES basis, directly from our projects or through our sales and shipping business. In addition, we have secured LNG regasification capacity in certain key import markets to support customers and further differentiate our integrated offering from that of other North American LNG exporters.

Our Commercial Arrangements and Strategy

Our commercial strategy is intended to capture value across the full lifecycle of our LNG facilities—during testing and commissioning, operations under contracted sales agreements, and through the sale of excess production capacity. We employ a portfolio contracting approach designed to sell sufficient term liquefaction capacity to support financing while optimizing revenue and cash flow. This framework includes:

•Commissioning sales, representing LNG produced and sold, on a forward, spot or short-term contracted basis, during the testing and commissioning phase prior to COD;

•Contracted SPAs, generally consisting of long‑term agreements with third‑party customers that commence upon achievement of COD or a firm start date, and provide predictable revenue streams that have historically supported project financing; and

•Excess capacity sales, representing LNG produced above guaranteed nameplate capacity or Contracted SPA commitments and marketed under short‑, medium‑, or long‑term arrangements, providing commercial and pricing flexibility.

LNG produced by our facilities is sold to our customers directly from our projects or through our sales and shipping business on either a FOB, DPU or DES basis.

•The LNG sales price structure under our Contracted SPAs generally includes (i) a fixed liquefaction fee, a portion of which is subject to an annual adjustment for inflation; (ii) a variable commodity fee equal to at least 115% of Henry Hub per MMBtu of LNG; and (iii) a transportation charge, if sold on a DPU basis.

•The LNG sales price structure of our commissioning sales and excess capacity sales generally aligns with our Contracted SPAs for FOB delivery, whereas our DES agreements are structured with a single sales price that includes transportation and is indexed to foreign gas markets, such as TTF or JKM.

Taken together, we believe this contracting approach positions us to achieve a balanced revenue mix across long‑term contracted volumes and opportunistic spot or medium‑term sales.

Commissioning Sales

Our modular design allows a phased start-up of our LNG production facilities and the generation and sale of LNG prior to COD. Due to our unique modular development approach and configuration consisting of many mid-scale liquefaction trains, which are delivered and installed sequentially, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-scale liquefaction trains. The commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction.

LNG produced during this phase is sold under master SPAs to customers as either single cargos or as strips of multiple cargos and are based on spot and/or forward prices, generally consisting of a liquefaction fee and a variable commodity fee, at the time of execution.

We expect to continue to generate proceeds from commissioning sales of LNG at each project until COD. The Calcasieu Project generated proceeds from commissioning sales of LNG beginning in the first quarter of 2022 through COD in April 2025. Similarly, the Plaquemines Project began commissioning sales of LNG in January 2025, which are expected to continue through the respective CODs of its two phases.

Contracted SPAs

As of December 31, 2025, we have executed 47.0 mtpa of SPAs with a well-recognized group of third-party customers. Approximately 96% of contracted volumes are under 20-year, fixed price sales and purchase agreements that provide stable, long-term cash flows. Under these SPAs, customers pay a fixed liquefaction fee—even if cargo deliveries are suspended or canceled (i.e., "take or pay")—plus a variable commodity fee for volumes delivered. These Contracted SPAs have historically served as the commercial foundation for obtaining non‑recourse project level financing, demonstrating contracted revenue visibility and creditworthy counterparties.

•Post-COD SPAs —Our project companies for the Calcasieu, Plaquemines, and CP2 projects have executed post‑COD SPAs under which LNG is sold based on the pricing structure described above, commencing upon achievement of COD of the relevant project or phase thereof. COD is deemed achieved only once the relevant project company has notified the customer that the relevant project has been completed and commissioned, including any ramp up period, and is capable of delivering LNG that meets contractual quality and quantity standards.

•Firm-start SPAs —Our sales and shipping business—through VG Commodities—has executed long-term SPAs under which LNG is sold based on the pricing structure described above, commencing on set dates in 2029 and 2030. The LNG to be delivered under these agreements will be sourced by VG Commodities from the Calcasieu, Plaquemines or CP2 projects pursuant to VG Commodities' intercompany excess capacity SPAs. We expect the obligation to deliver under these contracts will transition to CP2 upon achievement of COD of the relevant phase of the CP2 Project.

Together, we believe that these Contracted SPAs, combined with our modular and capital‑efficient development model, support our ability to finance, construct, and bring projects online on an accelerated timeline when compared to traditional stick-built projects.

Excess Capacity Sales

Our facilities are designed to produce LNG in excess of their guaranteed nameplate capacity—by as much as 40% annually—reflecting the annualized expected production capacity under normal ambient weather conditions. The performance of liquefaction trains during commissioning at the Plaquemines Project supports these production capacity expectations. In addition, our recent filings with the FERC contemplate expected annualized peak production capacity performance in excess of this 40% figure at the Plaquemines Project. This excess capacity creates the potential for additional cash proceeds from our projects.

Post-COD, any LNG produced in excess of nameplate capacity from the Calcasieu, Plaquemines, and CP2 projects is intended to be sold to VG Commodities under intercompany excess capacity SPAs. LNG sold under such intercompany excess capacity SPAs can, to the extent not previously committed to third parties, be resold to third-party customers at our discretion under contracts of various tenors, providing flexibility to manage pricing exposure and optimize portfolio returns. We expect to enter into similar intercompany excess capacity SPAs for our other development projects. VG Commodities has contracted to resell a portion of the excess capacity from the Calcasieu Project to a third-party pursuant to a long-term SPA.

Our Project Development and Construction Strategy

Our project design utilizes proven liquefaction system technology and equipment in a unique mid-scale, factory-fabricated configuration developed by Venture Global. Rather than utilizing two or three large, complex liquefaction trains, our facilities utilize multiple electric motor driven mid‑scale trains that are prefabricated in Italy and shipped to the project site fully assembled and packaged for installation, allowing on‑site work to progress in parallel with fabrication.

We believe our innovative configuration, long-term equipment contracting strategy, and internal owner-led engineering, procurement and construction management ("EPCM") approach significantly reduce project costs, construction time and schedule risk as compared to traditional LNG projects. This combination enables greater cost competitiveness while supporting the early production of commissioning cargos. For example, both the Calcasieu and Plaquemines projects began LNG production approximately two and a half years after their respective final investment decisions, while significant construction work was still underway. The CP2 Project is currently targeting similar or improved execution timelines.

By leveraging standardized factory-fabricated equipment and our “design one, build many” methodology, we aim to continuously apply lessons learned from earlier projects to subsequent developments—enhancing execution efficiency, reducing costs, accelerating delivery, and expanding capacity.

Bolt-on Expansion Opportunities

Our projects are sited and designed to enable optimization, additional capacity and bolt‑on expansions. Each facility incorporates laydown areas, shared infrastructure redundancies and standardized liquefaction modules designed for scalable build-out. This design provides flexibility in phasing and scope of future bolt-on expansions, allowing us to respond efficiently to market demand while leveraging existing infrastructure.

Any incremental equipment is expected to utilize certain pre‑existing plant facilities and infrastructure, such as marine offloading facilities, LNG storage tanks, and perimeter walls. Bolt-on expansion projects may require incremental natural gas supply arrangements, new or expanded pipelines (which can be developed in phases), and associated transportation capacity to support additional throughput.

Testing and Commissioning Process

Due to our unique design using numerous mid-scale liquefaction trains, which are delivered and installed sequentially, it is necessary to commission and test our LNG facilities over a longer period of time than traditional LNG facilities. The operation and commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction, serially bringing modules and production capacity online for commissioning. This important reliability and technical requirement results in earlier production of LNG than with traditional LNG facilities.

Our Complementary Infrastructure

Pipeline Projects

We are in varying stages of construction and development of pipelines to establish complementary gas transportation for our LNG projects. For example, we partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, to jointly develop the approximately 190-mile Blackfin Pipeline project, a 48-inch intrastate pipeline designed to transport Permian and Eagle Ford-sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline. In addition to the Blackfin Pipeline, we are developing several other pipelines intended to support production capacity for Phase 2 of the CP2 Project and our bolt-on expansion projects.

Shipping

To further vertically integrate our business and expand access to premium markets that have no or limited LNG transportation options, we are building a fleet of LNG tankers. We have contracted to acquire nine LNG tankers, seven of which have been delivered. The remaining LNG tankers are under construction and scheduled for delivery in 2026. In addition, we have chartered two LNG tankers to supplement delivery capacity until our full fleet is available.

LNG Regasification Capacity

We have secured LNG regasification capacity in the United Kingdom and Greece, which is expected to allow us to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers.

Carbon Capture and Sequestration Initiative

We plan to deploy carbon capture and sequestration systems adjacent to our Louisiana projects to reduce CO₂ emissions by compressing CO2 emissions from our projects and injecting them into subsurface saline aquifers near our project site. In July 2023, we submitted an application to the U.S. EPA for a Class VI well permit in respect of the Calcasieu Project and CP2 Project. We are in the process of completing the remaining applications for regulatory approval in respect of our current projects. We have also secured the requisite pore space leases with the State of Louisiana.

Our Liquefaction Projects

(1) Nameplate capacity of 10.0 mtpa.

(2) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, contractor engagement and other factors.

Project Construction, Commissioning and Completion

Construction of the Calcasieu Project is complete, and the facility achieved COD on April 15, 2025. COD followed completion of commissioning and testing to confirm the ability to safely and reliably produce LNG at designed nameplate levels. During commissioning, additional remediation work was performed on the power island system’s heat‑recovery steam generators after the manufacturer’s fabrication change led to leakage issues. In addition, the gas pre‑treatment units required performance rectification before achieving Lender Reliability Performance Test completion and COD declaration.

As of December 31, 2025, the Calcasieu Project executed approximately 28.1 million work hours with a TRIR of 0.12, significantly outperforming the U.S. industry average of 2.2 for 2024.

Upon achievement of COD, the Calcasieu Project commenced deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the Calcasieu Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025.

(1) Consists of six contracts, primarily with investment‑grade offtakers.

(2) Represents 1.2 mtpa of expected annualized production capacity in excess of the 10.0 mtpa nameplate capacity of the facility. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules. Any LNG produced in excess of nameplate capacity is sold under an intercompany excess capacity SPA between VGCP and VG Commodities.

(1) Nameplate capacity of 20.0 mtpa.

(2) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the Plaquemines Project from 27.2 mtpa to 35.0 mtpa. We have a pending application with DOE to increase the authorized exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa, and we intend to submit another DOE export application in the first half of 2026 to increase the authorized export volumes to 35.0 mtpa. See—Governmental Regulationof this Item 1.

Project Construction and Commissioning

The Plaquemines Project is being constructed pursuant to two EPC contracts, one per phase, or the Plaquemines EPC Contracts, entered into with KZJV. Under the Plaquemines EPC Contracts, VGPL is responsible for executing or directly managing significant scopes of work. Baker Hughes, UOP and CB&I are each providing and constructing the mid-scale, factory-built liquefaction trains and power island systems, the pre-treatment system, and storage tanks, respectively.

As of December 31, 2025, all 36 liquefaction trains were operating and capable of producing LNG, while still undergoing testing and commissioning. In addition, the final portion of the Gator Express Pipeline was placed in service by FERC in December 2024. While construction remains ongoing, portions of the facility are undergoing commissioning activities. Our gradual commissioning process starts with addressing identified operational deficiencies, testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities. For example, one issue that has arisen relates to substantial delays in the operation of our combined cycle power island system. To mitigate such delays, we have permitted and incorporated 400 MW of temporary power at the Plaquemines facility. This allows us to progress commissioning efforts, including the production and sale of commissioning cargos, while we complete the construction of our combined cycle power plants. Despite these challenges, the Plaquemines Project has exported a significant number of commissioning cargos while construction, rectification, and reliability adjustments continue.

We currently estimate that approximately $0.6 billion to $1.0 billion of the Total Project Cost for the Plaquemines Project has yet to be paid as of December 31, 2025. Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary, macroeconomic, and regulatory environment. However, the costs to complete the Plaquemines Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. 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 factorsof this Form 10-K.

As of December 31, 2025, the Plaquemines Project had executed approximately 90.6 million work hours with a TRIR of 0.18, significantly outperforming the U.S. industry average of 2.2 for 2024.

As facility testing and commissioning continue, the Plaquemines Project has exported commissioning cargos to various customers consistent with our commissioning sales strategy.

Upon achievement of COD for the respective phases of the project, the Plaquemines Project will begin deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the Plaquemines Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025:

(1) Includes five and seven contracts for Phases 1 and 2, respectively, primarily with investment‑grade offtakers.

(2) Represents 8.0 mtpa of expected annualized production capacity in excess of the 20.0 mtpa (Phase 1 – 13.3 mtpa; Phase 2 – 6.7 mtpa) nameplate capacity of the facility. Additional approvals from FERC and DOE are required to produce and export at this level of expected annualized production capacity. See—Governmental Regulationof this Item 1. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules. Any LNG produced in excess of nameplate capacity is sold under the respective intercompany excess capacity SPA between VGPL and VG Commodities.

(1) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See—Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(2) Nameplate capacity of 17.8 mtpa.

(3) In November 2025, we filed applications with the FERC and DOE proposing a 31.0 mtpa expansion of the Plaquemines Project (the “Plaquemines Expansion Project”). The Plaquemines Expansion Project replaces the Delta Project which we withdrew from the FERC pre-filing process on June 10, 2025, as described in—Governmental Regulation of this Item 1.

The Plaquemines bolt-on expansion project (the "Plaquemines Expansion Project") represents an evolution of our development strategy in Plaquemines Parish, LA and supersedes the previously contemplated Delta Project. In November 2025, we filed an application with the FERC proposing a 31.0 mtpa expansion of the existing Plaquemines Project LNG facilities in lieu of further pursuing the Delta Project, which represented a higher cost and longer duration development opportunity. Accordingly, the Delta Project was withdrawn from FERC pre-filing in June 2025, as described in —Governmental Regulation of this Item 1.

The Plaquemines Expansion Project is planned to be interconnected with the existing Plaquemines LNG terminal and is expected to share certain existing facilities, including LNG storage tanks, LNG loading berths, and marine facilities. Further, the project is expected to incorporate additional liquefaction trains and associated equipment within a site immediately adjacent to the existing Plaquemines Project site. We expect to develop, finance and construct the Plaquemines Expansion Project in phases, focusing first on the installation of liquefaction trains that can quickly be added to the existing infrastructure with limited expansion of ancillary equipment.

The Plaquemines Expansion Project will not include any new FERC-jurisdictional interstate pipeline facilities; rather, feed gas for the project will be delivered through a non-jurisdictional intrastate pipeline system that has yet to be constructed, connecting the project to the existing natural gas pipeline network in northern Louisiana.

As of December 31, 2025, we have completed significant engineering studies and simulations, including certain marine berth simulations, in support of the project. We expect to begin construction of the Plaquemines Expansion Project upon receipt of all required regulatory approvals and are targeting the start of construction by the second half of 2027, subject to regulatory approvals and the execution of sufficient SPAs to support project financing.

(1) Nameplate capacity of 20.0 mtpa (14.4 mtpa and 5.6 mtpa for Phases 1 and 2 of the CP2 Project, respectively).

(2) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the CP2 Project to 35.0 mtpa. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations 35.0 mtpa. Both the FERC and DOE Non-FTA Nations authorizations are subject to on-going appeals. See—Governmental Regulation of this Item 1. See—Governmental Regulation of this Item 1.

Project Engineering, Procurement, and Construction

In 2025, we commenced site work on Phase 1 of the CP2 LNG facility and the CP Express Pipeline following receipt of final approval and notices to proceed with on-site construction from the FERC. In July 2025, Phase 1 of the CP2 Project achieved FID and obtained project financing to fund the development and construction of Phase 1 of the CP2 Project. In October 2025, CP2 received the final authorization from the DOE to export LNG to Non-FTA Nations. We have completed substantial engineering, procurement, manufacturing, and off-site construction work for Phase 2 of the CP2 Project in advance of a final investment decision, the timing of which remains subject to certain market and other conditions. See—Governmental Regulation and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projectsof this Form 10-K.

In addition to the CP Express Pipeline, we have partnered with WhiteWater Midstream, LLC to jointly develop the Blackfin Pipeline. The Blackfin Pipeline is an intrastate pipeline designed to facilitate the transportation of Permian and Eagle Ford Basin-sourced natural gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline.

For the CP2 Project, we are managing and expect to continue to manage additional scopes of work beyond those managed in our previous two projects by directly taking on incremental oversight, contract management and coordination responsibilities, based on lessons learned and the relationships we have fostered with construction and fabrication subcontractors while developing the Calcasieu and Plaquemines projects. Additionally, we have added nitrogen rejection units in the CP2 design. This facilitates the use of Permian Basin-sourced high nitrogen content natural gas, which often trades at a substantial discount to Henry Hub index pricing, in the production of LNG at the CP2 Project.

We currently estimate that the Total Project Costs for the first and second phase of the CP2 Project will range between approximately $32.5 billion and $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. The estimated Total Project Cost for the first and second phases of the CP2 Project has increased due to factors including design modifications to accommodate increased production levels and allow for potential future bolt-on expansions to the CP2 Project. Additional drivers include increased contingency reserves for the potential impact of tariffs in place as of December 31, 2025, but does not reflect potential incremental tariff exposure that may arise as a consequence of evolving tariff policies. Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary environment and current known tariff exposure. However, the costs to complete the CP2 Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. 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 of this Form 10-K.

As of December 31, 2025, the CP2 Project had executed approximately 13.2 million work hours with a TRIR of 0.18, significantly outperforming the U.S. industry average of 2.2 for 2024.

The CP2 Project has not yet commenced LNG production or commissioning activities. However, CP2 has executed post-COD SPAs with third-party customers and intercompany excess capacity SPA with VG Commodities. In addition, VG Commodities has entered into Firm-start SPAs with third-party customers providing for the delivery of LNG from the CP2 Project upon achievement of COD of phase 2 of the project or from Venture Global's portfolio at a fixed start date. We expect some of these SPAs will transition to the CP2 Project at that time.

Upon achievement of COD for the respective phases of the project, the CP2 Project will begin deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the CP2 Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025:

(1) Includes ten contracts, primarily with investment‑grade offtakers.

(2) Represents Firm-start SPAs with VG Commodities which is expected to transition to CP2 upon COD of Phase 2 of the project. See –Our Sales and Shipping Business of this Item 1.

(3) Represents 9.0 mtpa of expected annualized production capacity in excess of the 20.0 mtpa (Phase 1 – 14.4 mtpa; Phase 2 – 5.6 mtpa) nameplate capacity of the facility. Additional approvals from FERC and DOE are required to produce and export at this level of expected annualized production capacity. See—Governmental Regulationof this Item 1. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules. Any LNG produced in excess of nameplate capacity is sold under an intercompany excess capacity SPA between Calcasieu Pass and VG Commodities.

As of December 31, 2025, the CP2 Project had 3.0 mtpa of nameplate capacity that had not yet been contractually committed under post-COD SPAs. In February 2026, the CP2 Project executed a 20-year post-COD SPA for the delivery of 1.5 mtpa from Phase 2 of the CP2 Project, increasing the total expected capacity post-COD under contract from 26.0 mtpa to 27.5 mtpa. After achieving COD, we intend to market and sell any quantities of LNG that are not contractually committed through VG Commodities.

(1) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See—Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(2) Nameplate capacity of 6.6 mtpa.

(3) We intend to file applications with the FERC and DOE proposing a 11.7 mtpa expansion of the CP2 Project (the "CP2 Expansion Project") in the first half of 2026. See—Governmental Regulation of this Item 1.

The CP2 bolt-on expansion project (the "CP2 Expansion Project") is expected to incorporate additional liquefaction trains, equipment, and a new FERC-jurisdictional interstate pipeline facility with existing equipment and infrastructure from the CP2 Project. The majority of the expansion facilities will be constructed within the existing industrial footprint and inside the perimeter wall that encloses the current CP2 Project site, minimizing additional requirements and infrastructure modifications. We expect to develop, finance and construct the CP2 Expansion Project in phases, focusing first on the installation of liquefaction trains that can quickly be added to the existing infrastructure with limited expansion of ancillary equipment. We believe this phased development of the bolt-on expansion, once implemented, will demonstrate our ability to quickly deploy incremental capacity within an established footprint in a cost-efficient manner.

As of December 31, 2025, we have completed significant engineering studies and simulations, including certain marine berth simulations, in support of the project. We expect to begin construction of the CP2 Expansion Project upon receipt of all required regulatory approvals and are targeting the start of construction by the first half of 2027, subject to the execution of sufficient SPAs to support project financing.

CP3 Project

(1) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See—Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects. As of the date of this Form 10-K, no FERC and no DOE filings have been made and none of the necessary approvals for the CP3 Project have been obtained.

(2) Nameplate capacity of 33.3 mtpa.

Although we completed our initial consultation with FERC in December 2024, as of December 31, 2025, we had not initiated the pre-filing process for the CP3 Project with FERC or entered into definitive agreements necessary for the project’s development and construction. While preliminary engineering and feasibility work, including certain marine berth simulations, have been conducted in support of early-stage development, overall project advancement remains in its initial development stage as we continue to evaluate market conditions and sequencing across our project portfolio. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects, but we intend to prioritize our lower-cost bolt-on expansion opportunities ahead of the CP3 Project.

Our Sales and Shipping Business

Our sales and shipping business, which includes the activities of our wholly owned entity, VG Commodities, serves as the Company's commercial arm for the sale of LNG volumes acquired from the Company's LNG projects in excess of that currently contracted directly by the projects, and manages shipping to optimize portfolio value and flexibility. VG Commodities engages in both third-party sales and intercompany purchase arrangements, on a short-, medium- and long-term basis, enabling the efficient commercial marketing and contracting of LNG production across Venture Global's projects.

VG Commodities has entered intercompany excess capacity SPAs with the Calcasieu, Plaquemines and CP2 projects to acquire LNG produced in excess of each project's nameplate capacity. This provides VG Commodities access to up to 18.2 mtpa of incremental LNG subject to operating conditions, maintenance schedules and other factors affecting production, and permitting. One half of the excess LNG VG Commodities acquires from the Calcasieu Project is committed for sale under a 20-year FOB SPA with a third-party at prices indexed to international market gas rates. The remainder of VG Commodities' excess volumes may be resold to other third party customers under contracts of varying tenors, providing pricing flexibility and portfolio optimization opportunities. We expect to enter into similar intercompany excess capacity SPAs for our other development projects.

VG Commodities has also executed Firm-start SPAs with third-party customers to sell a total of 2.5 mtpa of LNG, generally on a long-term basis, commencing between 2029 and 2030. These agreements provide fixed start dates for the sale of LNG sourced from the CP2 Project or, prior to COD of the respective phases of the project, from excess capacity sourced from the Calcasieu, Plaquemines or CP2 projects. The pricing terms are consistent with the Company's other long-term post-COD SPAs, including both a fixed facility and a variable commodity fee. We expect the obligation to deliver under these contracts will transition to CP2 upon achievement of COD of the relevant phase of the CP2 Project.

VG Commodities intends to maintain a balanced portfolio of long-term, medium-term and short-term sales to optimize pricing outcomes, manage risk and maximize returns across the Venture Global asset base.

Shipping and Logistics

VG Commodities manages the Company's shipping portfolio, including wholly owned and chartered LNG tankers, to support delivery commitments under its SPAs and provide flexibility in matching cargo destinations with market demand. This managed LNG delivery and logistics capability is the beneficiary of LNG regasification capacity the Company has secured at the Alexandroupolis LNG terminal in Greece and forthcoming regasification capacity under construction at the Grain LNG terminal in the United Kingdom. These long-term, contracted regasification positions support reliable import access for our managed LNG sales to important import access points to the European natural gas market and support Venture Global's broader vertical integration strategy to expand its market reach.

Natural Gas Supply and Transportation

We procure and transport natural gas required to produce LNG at our facilities under long-term supply and transportation commitments with domestic producers and midstream pipeline operators. Our current portfolio of feed-gas supply agreements supports the Calcasieu, Plaquemines and CP2 projects. We will continue to expand this portfolio to meet the needs of our ongoing and future developments.

Through lateral pipelines that we developed, each project is connected to multiple major interstate or intrastate pipelines, providing access to highly liquid supply from leading U.S. shale formations—including the Haynesville, Permian and Marcellus/Utica basins—through interconnections with systems such as ANR Pipeline, Texas Eastern Transmission, Sabine Pipe Line, Columbia Gulf and Tennessee Gas Pipeline. Our existing gas-transportation agreements generally have 10- to 20-year terms and include options for extension.

To enhance supply diversity and reliability, we are developing additional pipeline infrastructure independently and in coordination with experienced third-party operators. Current initiatives include the Blackfin, Marais and Cloud Connector pipelines, which are expected to serve future phases of the Plaquemines and CP2 projects and other future projects or bolt-in expansions. These projects will provide incremental delivery capacity from the Permian, Haynesville, Eagle Ford and mid-continent shale formations and ensure stable, cost-effective access to feed-gas supply for our LNG facilities.

Our EPCM Model Approach and EPC Contracts

Since our first project, we have applied a hands-on approach to project execution by contracting directly with EPC contractors and key equipment suppliers rather than relying on traditional lump-sum, turn-key structures common in the LNG industry. Our integrated, owner-driven model has been a core differentiator in our ability to deliver projects efficiently and cost effectively. Building on that foundation, we have now advanced to an owner led EPCM model in the construction of the CP2 Project. Under this approach, we manage procurement and construction activities directly rather than outsourcing such activities to a single EPC contractor, thereby enabling our greater control over project execution, scheduling and cost outcomes. The EPCM model allows us to: (i) capture synergies across multiple projects by applying consistent design standards and vendor relationships, (ii) maintain continuity of specialized expertise across phases and sites, (iii) leverage historic performance and financial data to enhance transparency, staffing levels, efficiency and accountability over subcontractor performance and material costs, and (iv) mitigate exposure to redundant EPC administrative and back office cost escalation. By retaining these capabilities internally, we strengthen operational resilience in a market constrained by skilled labor and increase our ability to execute projects on accelerated timelines at lower capital cost per unit of production.

We constructed the Calcasieu Project pursuant to an EPC contract and have entered into EPC contracts for both phases of the Plaquemines and CP2 projects. While these agreements require each contractor to integrate equipment and facilities and guarantee full operation of the LNG export facilities, the nature of those agreements reflects a significant shift in our execution model. For the CP2 Project, we have assumed a substantially larger portion of engineering, procurement, and construction management activities directly—expanding our EPCM model beyond the level deployed at the Plaquemines Project. For future developments, we plan to negotiate EPC contracts with similar terms while expanding our self-managed EPCM activities, consistent with the approach used for our CP2 Project execution.

Phases 1 and 2 of the Plaquemines Project are governed by EPC contracts with KZJV, structured as reimbursable arrangements with target prices and schedule-based incentives. For example, KZJV will be paid a reimbursable sum for its scope of work, where we will reimburse KZJV for all reimbursable costs incurred in connection with the relevant work (such as costs for materials, transportation and equipment), plus a margin to cover overhead costs and expenses as well as an agreed profit margin. However, all other costs will not be reimbursed and will be borne by KZJV. The estimated reimbursable sum represents the “target price” for each phase of the Plaquemines Project, which is reflected in our estimated Total Project Costs for the Plaquemines Project. The target price is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by KZJV or changes to the project schedule. The CP2 EPC contracts with Worley follow similar terms adapted to project scope and timeline. All agreements include defined change-order procedures, milestone incentives and shared cost-savings mechanism that promote timely completion and performance compliance.

Under each such EPC contract that we have entered into for our projects, the EPC contractor has an obligation to deliver a facility capable of passing certain performance tests. Further, under each such contract, the EPC contractor warrants that (i) it will perform the work under the EPC contract in full compliance with such contract, (ii) the materials and the work will be designed, manufactured, engineered, constructed, completed, pre-commissioned, commissioned, tested and delivered in a workmanlike manner and in accordance with each respective EPC contract, our standards, all permits and approvals of government authorities, applicable codes and standards and all applicable laws, (iii) the work will conform to the specifications and descriptions in its EPC contract, will be new, complete, and of suitable grade for the intended function and use, will be free from defects in design, material and workmanship, and will meet the requirements set forth in its EPC contract, (iv) the materials will be composed and made of only proven technology, of a type in commercial operation at the effective date of its EPC contract, (v) if a serial defect (two or more of the same components experience a defect of an identical or nearly identical nature) occurs as to its work done under the EPC contract prior to the expiration of each respective warranty period, it will redesign, repair or replace any materials as necessary and extend each respective warranty period for that portion of the work that is redesigned, repaired or replaced for an additional 12 months, and (vi) during the warranty period, it will perform tests, inspections or other diagnostic services requested by us and correct any non-conforming work discovered.

Consistent with our EPCM approach, we coordinate project execution through a network of specialized contractors and suppliers rather than a single, turn-key provider. This decentralized framework allows us to allocate critical scopes among industry experts while maintaining direct control over integration and oversight across all facilities.

Baker Hughes Master Agreement

We maintain a master supply relationship with Baker Hughes under a long-term master agreement, (the "Baker Hughes Master Agreement"), that governs the supply of key liquefaction and power equipment for our LNG projects. The agreement secures equipment supply, pricing, and reserved manufacturing capacity sufficient to support our existing and future development projects, subject to our compliance with the agreement and timely execution of project specific purchase orders.

Purchase orders under this agreement establish the terms for equipment supply, delivery terms, testing and performance guarantees. Baker Hughes is obligated to meet specified performance, reliability, and LNG quality standards, and to remedy or compensate for any deficiencies through corrective work or liquidated damages. The agreement also provides for pre-negotiated forms of purchase orders and long-term service arrangements for maintenance and operational support—already exercised for the Calcasieu and Plaquemines projects—and includes performance-availability guarantees with related incentive and liquidated damage provisions.

We have executed the necessary purchase orders for our projects under construction—including the Plaquemines and CP2 projects—and the agreement provides remaining reserved manufacturing capacity that can accommodate future developments—including the Plaquemines Expansion and CP2 Expansion projects as well as the CP3 Project—subject to execution within the applicable timelines provided under the Baker Hughes Master Agreement.

Human Capital Resources

Our human capital is our most valuable asset, and we place a high premium on attracting, developing and retaining talented and high performing employees. As of December 31, 2025, we had over 2,000 full-time employees working on our EPCM, project development, project financing, corporate finance, legal, and LNG marketing teams. As we develop and construct our projects, we expect to create additional highly skilled engineering, construction, manufacturing, and operating full-time and contractor jobs in Louisiana, Texas, and Virginia. We offer our employees a wide array of company-paid benefits and performance incentives, which we believe are competitive relative to others in our industry. 117 of our international employees are represented by a labor union and subject to a collective bargaining agreement. This agreement is negotiated annually. We believe our relationship with our employees to be good.

Community Outreach

We are committed to creating lasting positive impacts in the communities where we operate. The construction and operation of our LNG facilities generate significant employment opportunities and contribute to regional and national economic growth through local hiring and broad participation by subcontractors and suppliers.

We prioritize hiring in-state and local workers and continually invest in workforce development through technical training and apprenticeship programs. For example, we partner with local colleges to provide residents near our project sites with industry certifications in fields such as electrical, welding and construction trades. In addition, our apprenticeship program offers hands-on technical training and clear pathways to full-time employment with Venture Global.

Beyond employment and training, we support the economic vitality of our host communities through ongoing contributions, local partnerships and property tax payments that provide substantial funding for parish infrastructure and public services. Through these activities, we aim to lead our industry in fostering sustainable community growth and opportunity.

Health and Safety

We are committed to providing a safe work environment across our businesses and strive towards best in class practices. We have built a dedicated Health, Safety, Security, and Environment, or HSSE, team that is accountable for the safe and responsible execution of our projects and reports to our Chief Operating Officer. At our project sites, our goal is to implement comprehensive safety programs that are appropriate for the hazards present at the various stages of construction and commissioning. This includes daily safety inspections, recurring safety trainings, and regular safety meetings. Our rigorous safety standards are continuously reviewed and updated to ensure they are fit for purpose within our workforce, and we aim to meet the highest possible benchmarks. We believe that a strong safety culture leads to better safety performance, better operational performance, and higher staff morale. Our aggregate 0.17 TRIR which, when compared to the industry average for 2024 of 2.2 according to the Bureau of Labor safety statistics, is among the best in our industry and stands as a testament to our commitments.

Governmental Regulation

Our operations are subject to extensive federal, state, and local regulation. Applicable laws require us to consult with applicable federal and state agencies, obtain and maintain applicable permits and authorizations, and comply with various ongoing regulatory requirements. This regulatory burden increases the cost of constructing and operating our projects, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. See Item 1A.—Risk Factors—Risk Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K for more information.

Federal Energy Regulatory Commission (FERC)

The siting, construction, and operation of our facilities are subject to FERC’s approval and ongoing regulation, as is the construction and operation of our natural gas pipelines.

Pursuant to the Natural Gas Act, or the NGA, any person proposing to site, construct, or operate facilities (including LNG terminals) to be used for the export of natural gas from the United States to a foreign country must obtain authorization from FERC. FERC exercises comprehensive regulation of interstate natural gas pipelines, including requiring a certificate of public convenience and necessity to construct and operate such a pipeline, and requiring that the rates and terms of service for pipeline transportation service be just and reasonable under the NGA.

In addition to the initial FERC process for each of our projects summarized below, we note that throughout the life of each project, our LNG and pipeline facilities will be subject to ongoing FERC regulation and reporting requirements (as well as those of various other federal, state and local regulatory agencies). FERC’s jurisdiction under the NGA and NGPA allows it to impose civil and criminal penalties for any violations of the NGA or NGPA, and any rules, regulations or orders of FERC up to approximately $1.58 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

FERC authorized the Calcasieu Pass LNG facility and the TransCameron pipeline in February 2019. The pipeline was placed in service by FERC in April 2021, and the terminal achieved full-in service status with FERC authorization in April 2025 after completion of an extended commissioning process. In June 2025, FERC approved a subsequent amendment of its authorizations increasing permitted peak production capacity from 12.0 to 12.4 mtpa.

FERC authorized Phase 1 and 2 of the Plaquemines LNG facility and Gator Express pipeline in September 2019. Both pipeline laterals were placed in service by FERC during 2024, and commissioning of terminal facilities is ongoing under FERC supervision. In February 2025, FERC approved an increase in authorized capacity to 27.2 mtpa and in October 2025, granted an extension of time to complete construction and achieve full in-service status by December 2027. An additional application to increase permitted peak production capacity to 35.0 mtpa was filed in December 2025 and remains pending.

In November 2025, Venture Global Plaquemines LNG, LLC and Plaquemines Expansion, LLC filed a joint application with FERC for authorization to construct and operate the Plaquemines Expansion Project adjacent to the Plaquemines Project. The proposed facilities include 32 new liquefaction trains capable of up to 31.0 mtpa of additional peak liquefaction capacity. This application is currently under FERC review.

FERC authorized the CP2 LNG facility and the CP Express pipeline in June 2024. Following a supplemental environmental review initiated in an order on rehearing, FERC reaffirmed the authorization in May 2025, and on-site construction began in June 2025. Construction and subsequent commissioning of the CP2 LNG facility, as well as the construction of CP Express pipeline, are subject to ongoing oversight and needed approvals from FERC. An appeal of FERC's orders remains pending before the U.S. Court of Appeals for the D.C. Circuit. In December 2025, we filed an application to amend the authorization to increase permitted peak production capacity from 28.0 to 35.0 mtpa.

No application has been filed with FERC for the CP2 Expansion Project. Timing of any submission and approval depends on market conditions and regulatory priorities.

CP3 Project and Delta Project

No application application has been filed with FERC for the CP3 Project. Timing of any submission and approval depends on market condition and regulatory priorities. The previously proposed Delta Project was withdrawn from FERC's pre-filing process in June 2025 following the announcement of the Plaquemines Expansion Project noted above.

DOE Export Authorizations

Section 3 of the NGA requires any person seeking to import natural gas from, or export natural gas to, a foreign country to obtain authorization from the DOE. The DOE’s Hydrocarbons and Geothermal Energy Office, or HGEO (formerly named the Fossil Energy and Carbon Management Office), reviews applications to import or export natural gas.

The NGA sets forth separate standards of review for exports to (i) countries with which the United States has a free trade agreement requiring national treatment for trade in natural gas, or FTA Nations, and (ii) countries with which there is no such free trade agreement in effect, or Non-FTA Nations. Applications seeking authorization to export LNG to FTA Nations are deemed consistent with the public interest and must be granted without modification or delay. FTA Nations currently include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea, and Singapore. In contrast, Non-FTA Nations export applications are subject to a public interest review. HGEO will grant the requested authorization unless it finds, after providing for a public comment period, that the proposed exports will be inconsistent with the public interest, and may approve an application in whole or in part, and with such modifications and upon such terms and conditions as it deems necessary or appropriate. HGEO’s historical practice has been to act on long-term authorizations to export to Non-FTA Nations only after the FERC has authorized the siting, construction and operation of the associated LNG facilities.

On December 17, 2024, DOE publicly released a multi-volume study of its views of the potential effects of U.S. LNG exports on the domestic economy; U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects of U.S. trading partners; and the environment and climate—the 2024 LNG Export Study. DOE stated that it would use this study to inform its public interest review of and future decisions regarding exports to Non-FTA Nations. The period for public comment on the study expired on March 20, 2025.

On May 19, 2025, DOE issued its response to public comments on the 2024 LNG Export Study, concluding with detailed supporting analysis that LNG exports are consistent with public interest. Since that date, DOE has issued a series of orders authorizing US LNG exports, including certain orders for Venture Global projects addressed below. Nevertheless, there can be no assurance as to DOE’s future policies, or the impact of those policies on our existing and future projects, including the applications described below, or on any contracts related to our existing and future projects. For more information on these risks, see Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K.

HGEO authorized exports to FTA Nations for the Calcasieu Project in 2013 and 2014 and to Non-FTA Nations in March 2019 for a combined capacity of approximately 12.0 mtpa. All authorizations now extend through December 2050. DOE also amended the authorizations to include short-term commissioning exports, and approved an increase in authorized capacity to 12.4 mtpa in 2022 (FTA) and 2025 (Non-FTA).

HGEO authorized exports to FTA Nations for the Plaquemines Project in July 2016 and to Non-FTA Nations in October 2019 for a total capacity of 24.0 mtpa, with terms extended through 2050. DOE later amended these authorizations to include short-term export authority for commissioning volumes, consistent with the Calcasieu Project. In March 2022, we requested an increase to 27.2 mtpa; DOE approved that higher capacity for FTA Nations in June 2022 and is reviewing the Non-FTA request. Following our December 2025 FERC filing to uprate capacity to 35.0 mtpa, we plan to submit a corresponding DOE export application in the first half of 2026.

In November 2025, we filed a DOE application to export up to 31.0 mtpa from the Plaquemines Expansion Project to both FTA and Non-FTA Nations. The application is pending DOE action.

HGEO authorized 28.0 mtpa of exports to FTA Nations in April 2022 and to Non-FTA Nations in October 2025 following completion of its review of the 2024 LNG Export Study. An appeal of the Non-FTA order by environmental groups remains pending. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations to 35.0 mtpa, to align with our uprate request filed with FERC in December 2025.

As of December 31, 2025, no HGEO export application has been filed for the CP2 Expansion Project. We expect to seek authorization in parallel with our formal FERC application for the project.

CP3 Project

As of December 31, 2025, no HGEO export application has been filed for the CP3 Project. We expect to seek authorization in parallel with our formal FERC application for the project.

Department of Transportation Pipeline and Hazardous Materials Safety Administration

Our projects must comply with certain safety standards set by PHMSA. 49 C.F.R. Part 193, Federal Safety Standards for Liquefied Natural Gas Facilities, which establishes minimum federal safety standards for the siting, construction, operation, and maintenance of onshore LNG facilities and the siting of marine cargo transfer systems at waterfront LNG plants. These standards also incorporate by reference the National Fire Protection Association, Standard 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas.” Pursuant to a Memorandum of Understanding, or MOU, between FERC and PHMSA, PHMSA issues a Letter of Determination, or LOD, regarding compliance with the applicable safety standards for FERC jurisdictional LNG facilities, which is incorporated into the relevant FERC proceeding. Accordingly, PHMSA issued the requisite LOD for each of the Calcasieu Project (as well as its “uprate” amendment), the Plaquemines Project (and its first uprate), and the CP2 Project. PHMSA LODs will also be required for the Plaquemines Expansion Project and the uprate projects recently filed for both the Plaquemines Project and the CP2 Project, as part of each of the relevant FERC processes. Once constructed and operational, each of our LNG facilities’ compliance with the 49 C.F.R. Part 193 requirements will be subject to DOT’s inspection and enforcement program.

Other Governmental Permits, Approvals and Authorizations

The construction and operation of our projects is subject to additional federal and state permits, orders, approvals, and consultations required by other federal and state agencies, including the DOE, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Marine Fisheries Services, Federal Aviation Administration, U.S. Fish and Wildlife Service, EPA, Louisiana Department of Environmental Quality, Louisiana Department of Energy and Natural Resources, and U.S. Department of Homeland Security. We currently have all material permits required for our projects at their current respective stage of construction and operations. Permitting for the Plaquemines Expansion, CP2 Expansion, and CP3 projects remains ongoing.

Commodity Futures Trading Commission (CFTC)

We have entered into interest rate hedges, including interest rate swaps, in connection with our variable rate debt agreements, and we may enter into additional interest rate hedges and other derivatives in the future. Pursuant to authority granted by the CEA, the CFTC exercises federal oversight and regulation of the derivatives market in the United States for most types of derivatives and entities, like us, that participate in that market.

Among other CFTC requirements, the CFTC’s swaps rules impose a range of regulatory requirements on parties transacting in swaps that, among other things: (i) provide for the registration and regulation of Swap Dealers and Major Swap Participants; (ii) impose clearing and trade execution requirements for certain swaps, subject to certain exceptions; (iii) establish swaps recordkeeping and reporting regimes; and (iv) implement the CFTC’s anti-manipulation, anti-fraud, and anti-disruptive trade practice authority.

As a commercial end-user, we are subject to only limited CFTC swaps requirements. However, the application of these requirements to other market participants may affect the overall swaps market, including the costs and availability of the types of swaps we use to hedge or mitigate our commercial risks. In addition, the CFTC’s swap requirements remain subject to changes from future rule amendments, interpretive guidance and no-action relief, and the ultimate effect on our business of any changes to the rules or interpretive guidance, or of any new rules in the future, remains uncertain.

Environmental Regulation

Our projects are subject to various federal, state, and local environmental statutes and regulations intended to ensure the protection of the environment. In certain cases, these environmental laws and regulations require us to obtain permits and authorizations and engage in agency consultations prior to construction and operation of a project. Many laws and regulations restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment. In addition, our LNG tankers are subject to environmental regulations, rules and conventions adopted in the jurisdictions in which they call or are flagged, including requirements to record and report their fuel consumption, and to purchase and surrender emissions credits. Similarly, our downstream sales of LNG into, for example, the European Union, are subject to environmental-based monitoring and reporting adopted in those jurisdictions. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. See Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating and/or construction costs and restrictions of this Form 10-K for more information.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)

Certain aspects of our projects may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, which provides for the investigation, cleanup, and restoration of natural resources from releases of hazardous substances (not including “petroleum”). We may be subject to liability under CERCLA as a result of contamination at properties currently or formerly owned, leased, or operated by us or our predecessors or at third-party contaminated facilities to which we have sent waste for treatment or disposal. Liability under CERCLA can be imposed on a joint and several basis and without regard to fault or the legality of the conduct giving rise to contamination.

Clean Air Act (CAA)

Our projects are subject to the CAA and comparable state and local laws. Under the CAA, the EPA has the authority to control air pollution by issuing and enforcing regulations for entities that emit substances into the air. The EPA has promulgated regulations for major sources of air pollution and has delegated implementation of these regulations to state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality. In addition to having obtained relevant air permits from the Louisiana Department of Environmental Quality prior to construction of our projects, we are subject to ongoing emissions standards, requirements, and reporting obligations under the EPA rules, as well as under Louisiana, and in the case of the CP Express Pipeline and the Blackfin Pipeline, Texas state regulatory agencies.

Coastal Zone Management Act (CZMA)

The Coastal Zone Management Act, or CZMA, is intended to ensure the effective management, beneficial use, protection, and development of the nation’s coastal zone. Under the CZMA, participating states are required to develop management programs demonstrating how they will meet their obligations and responsibilities in managing their coastal areas. The Louisiana Department of Energy and Conservation, which administers the CZMA for each of our projects, issued a coastal use permit and related mitigation plan for the Calcasieu and CP2 projects, and an exemption for the Plaquemines LNG terminal due to its location within an area designed by Louisiana law as “fastlands” and a “no direct or significant impact” (NDSI) exemption for the Plaquemines marine facility.

Clean Water Act (CWA) and Rivers and Harbors Act

Our projects are subject to the CWA, which regulates discharges of pollutants into the waters of the United States, as well as analogous state and local laws. Under section 401 of the CWA, a federal agency may not issue a permit for any activity that may result in any discharge into the waters of the United States unless the state where the discharge would originate either issues a water quality certification verifying compliance with existing water quality requirements or waives this requirement. Additionally, section 404 of the CWA regulates the discharge of dredged or fill material into waters of the United States, including wetlands. Each of the Calcasieu Project, Plaquemines Project, and CP2 Project has received a water quality certification from the Louisiana Department of Environmental Quality, Water Quality Division. The Calcasieu, Plaquemines and CP2 projects have received CWA section 404 permits and section 10 of the Rivers and Harbors Act from the U.S. Army Corps of Engineers, or USACE, and permits from the Louisiana Department of Environmental Quality for the discharge of stormwater arising in connection with construction activities and industrial operations once construction is complete, and the discharge of wastewater generated during the operation of the facility.

Resource Conservation and Recovery Act (RCRA)

Under the Resource Conservation and Recovery Act, or RCRA, and comparable state hazardous waste laws, the EPA and authorized state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality, regulate the generation, transportation, treatment, storage, and disposal of hazardous waste. If hazardous wastes are generated or stored in connection with any of our projects, we would be subject to the requirements of such laws.

Endangered Species Act, or ESA, Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, and National Environmental Policy Act, or NEPA

Section 7 of the Endangered Species Act provides that any project authorized by any federal agency should not jeopardize the continued existence of any endangered species or threatened species, or result in the destruction or adverse modification of habitat of such species which is determined to be critical. The Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, establishes procedures designed to identify, conserve, and enhance essential fish habitat for those species regulated under a federal fisheries management plan. During the FERC review process for each of our projects, we engaged in consultation with the relevant federal agencies pursuant to the ESA and MSFCMA. Such consultation was completed for the Calcasieu Project, the Plaquemines Project, and the CP2 Project, but has not yet begun for any other future projects or bolt-on expansions.

The issuance of requisite permits and authorizations for our projects may be subject to environmental review under the National Environmental Protection Act, or NEPA. NEPA requires federal agencies to evaluate the environmental impact of major agency actions that may significantly affect the quality of the human environment, such as the granting of a permit or similar authorization for the development of certain projects. As part of NEPA review, federal agencies will prepare either an environmental assessment or a more detailed environmental impact statement that assesses the potential direct, indirect and cumulative impacts of a proposed project and is made available for public review and comment. The NEPA review process can lead to significant delays in approving such projects and the issuance of requisite permits. As a result of its NEPA review, a federal agency may decide to deny permits or other support for a project, or condition approvals on certain modifications or mitigation actions.

In May 2024, the Council on Environmental Quality, or CEQ, published its final “Phase 2” NEPA regulations, which included specific direction to account for both climate change and environmental justice effects in NEPA reviews. However, in January 2025, President Trump issued an executive order directing CEQ to rescind existing NEPA regulations and issue guidance and coordinate agency level regulations implementing NEPA that expedites permitting and prioritizes energy production. In response, CEQ rescinded its implementing regulations for NEPA reviews through an interim final rule in February 2025 that was adopted as final in January 2026. In light of CEQ’s rescission of its NEPA regulations, DOE and FERC have revised their own regulations and guidelines governing their respective NEPA review process. Unlike the now-rescinded Phase 2 NEPA regulations issued by CEQ, these revised regulations and guidelines do not include requirements to account for climate change or environmental justice. The outcome and impact of these legal developments cannot be predicted at this time.

Seasonality

Seasonal weather can affect the need for our LNG sales. While we expect that a substantial amount of our LNG will be sold under long-term Contracted SPAs, we have experienced, and expect to continue to experience, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets for our commissioning LNG sales. Additionally, excess LNG produced by our projects above the nameplate capacity that is sold to VG Commodities or otherwise can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium-, or long-term contracts, including on a forward spot basis, which would expose our revenues to such volatility and fluctuation in seasonal demand. Changes in temperature and weather may affect both power demand and power generation mix in the locations we service, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar, or wind, thus affecting the need for regasified LNG. These changes can increase or decrease demand for LNG and accordingly, fluctuations in revenue during quarters of high and low demand, respectively, could have a disproportionate effect on our results of operations, especially with regard to the LNG sold into the spot market.

Competition

The global LNG and natural gas markets are highly competitive. We compete with many participants across an integrated supply chain, including independent LNG producers, commodities marketing and trading firms, national energy companies, utility companies, and major multinational energy companies, primarily over supplies of natural gas and sales of our LNG. We believe our proprietary mid-scale, factory-built liquefaction train design, project execution excellence, access to well-priced and abundant, domestically sourced natural gas, simultaneous construction and integrated operations approach, with its associated commissioning cargos and proceeds, capital strength, leadership, and mission and values-led culture position Venture Global well to compete and thrive against this diverse competitive landscape.

We are subject to market-based price competition, reflecting supply and demand market pricing dynamics, with respect to revenue associated with any sales of our commissioning cargos and sales of LNG in excess of our nameplate capacity. We have experienced, and expect to continue to experience, competition with respect to LNG sales, including the effects of changes in supply and demand due to recent market volatility. The balance between the availability of LNG and the market demand for LNG significantly affects competition and the market price for our products. This dynamic is particularly acute for LNG sold on a forward spot or short-term contracted basis, such as any commissioning sales and excess capacity sales. Even after COD for our projects, we may continue to have a meaningful component of our production and sales subject to spot and short- or intermediate-term market dynamics. This may occur as a result of selling excess LNG production capacity through VG Commodities under short‑, medium‑, or long‑term arrangements,

Our current development projects, any future projects we develop, including expansions, will compete with other domestic and international suppliers, including other LNG projects being developed by us, on the basis of price per contracted volume of LNG.

With respect to our projects, our current and potential competitors include, but are not limited to, (1) national energy companies, such as QatarEnergy, (2) major multinational energy companies, including BP, Chevron, ConocoPhillips, ExxonMobil, Shell and Total, (3) independent LNG producers, including Cheniere and Freeport LNG, (4) utility companies, such as Sempra, and (5) commodities marketing and trading firms, such as Glencore, Trafigura, and Vitol. Some of our competitors may have financial, engineering, marketing, and other resources greater than we have, and some of them are fully integrated energy companies. Importantly, many of our competitors are also our customers with whom we have short-, intermediate-, and long-term contractual relationships.

Insurance

We maintain a comprehensive insurance program to insure potential losses to Venture Global and our projects from physical loss or damage, including due to floods and named windstorms, as well as third-party liabilities, during construction and subsequent operation. We expect to establish a similar comprehensive insurance program for our future development projects and bolt-on expansion projects at the appropriate and prudent time. We maintain a comprehensive insurance program to insure against customary risks and losses for our LNG tankers including protection and indemnity coverage and hull and machinery insurance as well as charterers’ liability insurance for our chartered LNG tankers. We may not be able to maintain adequate insurance in the future at rates that are considered reasonable. See Item 1A.—Risk Factors—Risks Relating to Our Business—We are unable to insure against all potential risks and may become subject to higher than expected insurance premiums. In addition, we retain certain risks as a result of insurance through our captive insurance of this Form 10-K.

Available Information

Our Class A common stock has been publicly traded since January 24, 2025 and is traded on the New York Stock Exchange under the symbol “VG.” Our principal executive offices are located at 1001 19th Street North, Suite 1500, Arlington, VA, 22209, and our telephone number is (202) 759-6740. Our internet address is www.ventureglobal.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Venture Global, Inc., Investor Relations, 1001 19th Street North, Suite 1500, Arlington, VA, 22209 or call (202) 759-6740. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers.