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Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.24pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.15pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.33pp
Lean -
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
adversely+7
against+6
adverse+5
limitation+4
volatility+3
Positive rising
perfected+4
successfully+2
assure+2
achieved+2
profitability+1
Risk Factors (Item 1A)
46,463 words
ITEM 1A. RISK FACTORS
You should carefully consider the risks and uncertainties described below, together with all other information contained in this Form 10-K, including those discussed in I t em 7.— Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K. If any of the following risks were to occur, our business, financial condition, results of operations and cash flow could be materially adversely affected. The following risks are not the only ones facing our company. Additional risks and uncertainties not currently known to us, or that we currently deem immaterial, may also impair or adversely affect us.
Risks Relating to Our Business
Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty.
We will continue to incur significant capital and operating expenditures while we develop, construct, and commission our projects. Our ability to maintain profitability and positive operating cash flows is primarily dependent on our ability to generate proceeds, and in turn net profits and operating cash flows, through the sale of LNG commissioning cargos, the sale of excess LNG that is produced above the nameplate capacity of our LNG projects, and, after COD occurs for a given project, through the sale of LNG pursuant to our post-COD SPAs, as well as our ability to monetize our other assets (such as pipelines, LNG tankers and downstream regasification capacity).
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
damages+8
unfavorable+8
arrears+3
against+3
breakage+3
Positive rising
best+4
achieved+1
positive+1
opportunities+1
strong+1
MD&A (Item 7)
14,902 words
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
During the year ended December 31, 2025, the Company's sales and shipping business met the criteria to be a reportable segment. Prior to the year ended December 31, 2025, sales and shipping was not quantitatively material for reporting purposes and was combined with corporate activities as corporate, other and eliminations. Prior period presentations included within Item 7. –– Management's discussion and Analysis of Financial Condition and Results of Operations of this form 10-K has been recast to conform to the current segment reporting structure.
For discussion of the Company's year ended December 31, 2024 compared to the year ended December 31, 2023, refer to Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Form 10-K filed with the SEC on March 6, 2025.
For 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 our projects prior to achieving COD. Although we have generated proceeds from the sales of commissioning cargos at the Calcasieu Project from first quarter of 2022 until COD was achieved in April 2025, and also at the Plaquemines Project since January 2025, such sales of commissioning cargos are limited in duration, and subject to a number of material uncertainties and risks. We are obligated to cease sales of commissioning cargos once the relevant COD occurs. The duration of the commissioning period at the Calcasieu Project, which was extended by a force majeure event, and the amount of proceeds we generated from the sales of commissioning cargos from the Calcasieu Project and also 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 of our projects or expansions thereof for any future 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 had an extended commissioning period due to unanticipatedchallenges with equipment reliability 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 of our other projects or expansions thereof.
Our ability to generate sales of LNG at each project or expansion thereof following COD, depends on our ability to successfully commence and maintain deliveries under our post-COD SPAs for such project or expansion, and also on our ability to produce and sell LNG in excess of the nameplate capacity of such 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. In addition, such revenues may be subject to increased volatility when compared to our long term post-COD SPAs if we choose to enter into any shorter term SPAs or if we choose to sell any LNG in excess of the nameplate capacity of our projects on a spot or short term basis.
There is no guarantee that we will achieve COD for any of our projects or expansions thereof, within the anticipated timeframes or at all, including as a result of risks described 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. 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 our projects that have not yet achieved COD including any expansions thereof.
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In addition to our post-COD SPAs, we have also entered into certain Firm-start SPAs. Our ability to satisfy our obligations under such Firm-start SPAs following the applicable firm start dates will depend in part on our ability to produce sufficient LNG cargos, either before or after COD, or in excess of nameplate capacity. While we expect to produce sufficient LNG volumes prior to the start date of each Firm-start SPA, there can be no assurance that our projects or bolt-on expansions will not be delayed, in which case we may not produce sufficient LNG to meet our obligations under the relevant Firm-start SPAs.
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 our projects prior to achieving COD and our ability to generate sales of LNG following COD at 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.
As a result, there is significant uncertainty about our ability to maintain profitability and positive operating cash flows.
We have only a limited track record and historical financial information, and there is no assurance that our business will be successful over the long term.
We first generated proceeds from sales of commissioning cargos at the Calcasieu Project only in the first quarter of 2022, and prior to that we incurred significant losses from operations and negative cash flows from operations.
In addition, as of December 31, 2025, a significant portion of the proceeds we have generated were 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 or for any of our other projects or 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 had an extended commissioning period due to unanticipatedchallenges with equipment reliability 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 of our other projects or expansions thereof.
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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 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 had an extended commissioning period due to unanticipatedchallenges with equipment reliability before COD occurred in April 2025, may not be indicative of the duration of the commissioning period or the amount of proceeds for any of our other projects or 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.
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.
A key element of our business strategy is to generate proceeds from the sale of LNG at 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 from our 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 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 generated from 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 during the commissioning phase for the Calcasieu Project and the Plaquemines Project, and expect to continue to experience during the respective commissioning phase for our other future projects and expansions, significant volatility in the proceeds generated from the sales of commissioning cargos. Accordingly, the proceeds we have generated from such sales of commissioning cargos to date, may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any of our other projects or 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
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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 our 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 capacity, 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 depends 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, 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 these prices 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.
As a result, we may experience significant volatility in any proceeds we generate from sales of post-COD LNG cargos at our projects, in particular if we reduce the proportion of such cargos that are committed under long-term SPAs. Moreover, if we are not able to effectively optimize sales of such cargos in the future, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We have not entered into SPAs with customers for the total expected nameplate capacity at Phase 2 of the CP2 Project, or other future projects or 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.
Our ability to generate revenue and cash flow is partially based on our ability to enter into long-term SPAs with customers with respect to the expected nameplate capacity of our projects. Changes in market conditions relating to, among other factors, the price of natural gas in the United States and the price of LNG in international markets could adversely affect the competitiveness of our projects and our ability to enter into such SPAs, which could adversely impact our potential revenues.
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, 2025, Phase 2 of the CP2 Project has contracted to sell 1.0 mtpa of LNG under a 20-year SPA. The obligation to make LNG available under the post-COD SPAs commences from the occurrence of COD for Phase 2 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 any of our other future projects or expansions and have not yet begun actively marketing the expected nameplate capacity for such other future projects or expansions. While taking FID for a given project, including any phase or expansion thereof, is subject to numerous factors, we
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may elect to proceed with FID for Phase 2 of the CP2 Project, 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.
Our revenues and operating margins may be adversely affected if we are unable to produce and sell liquefaction capacity in excess of the nameplate capacity of our facilities.
A key element of our business strategy is to generate revenue from the sale of LNG produced at each of our projects in excess of the nameplate capacity of the relevant project after such project achieves COD.
We aim to develop and operate our LNG facilities to be capable of producing greater excess capacity at each of our projects, in some cases by as 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.
We generally plan to retain flexibility to sell any excess LNG on a spot basis, or on a short-, medium- or long-term basis. Our ability to sell any such LNG will be subject to a number of risks and uncertainties outside our control, and there can be no assurance as to when, or on what terms, we will be able to sell any such excess LNG, if at all. As a result, revenues from the sale of any such excess LNG may vary significantly depending on prices and conditions in the international LNG markets and depending on when a contract for sale is executed, and the terms of those contracts may not always be favorable.
To the extent we are unable to sell such excess 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 excess 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 that 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 intercompany excess capacity 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). VG Commodities has 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.
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Our customers or we may terminate our SPAs if certain conditions are not met or for other reasons.
Each of our SPAs contains or will contain various termination rights allowing our current and future customers to terminate, or be relieved from their contractual obligations under their SPAs including, without limitation:
• with respect to certain post-COD SPAs, the failure of certain conditions precedent to be satisfied or waived by a specified date, or delays in the occurrence of COD beyond a specified time period;
• if we fail to make available specified scheduled cargo quantities;
• upon the occurrence of certain extended events of force majeure ;
• if we have been held liable in excess of certain liability caps and we did not agree to increase such liability caps as specified under the relevant SPA;
• our failure to satisfy our contractual obligations after an event of default and after any applicable cure periods; and
• the occurrence of certain change of control events.
While we could potentially replace any SPAs that are terminated by our customers or us, we may not be able to replace these SPAs on similar or favorable terms, or at all, if they are terminated. Further, under certain financing agreements, we may be required to maintain in effect (subject to our ability to replace them over a certain period of time that may extend up to 180 days) certain long-term SPAs for a particular project, and any breach of such requirement after the applicable grace period may, unless certain prepayments are made, result in an event of default under such agreements, as well as a cross-default under our other financing agreements for that project or otherwise. As a result, a termination of certain SPAs could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our ability to generate cash under our Contracted 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 continue having a limited number of customers to whom we sell LNG under our Contracted SPAs and sales by VG Commodities. For example, as of December 31, 2025, we have executed 47.0 mtpa of post-COD SPAs and Firm-start SPAs with 24 customers with respect to LNG from our projects, of which 45.2 mtpa is contracted on a 20-year basis and 1.8 mtpa is contracted on a short- and medium-term basis. For the year ended December 31, 2025, approximately 50.0% of our revenue for the period from individual external customers was concentrated across three customers. Moreover, for the year ended December 31, 2025, we had one customer which represented approximately 23% of our revenue for that same period.
The ability of our customers to perform their respective obligations to us will depend on numerous factors that are beyond our control. Our future results, our ability to service any debt we may incur and our liquidity are substantially dependent upon the performance of these customers under their contracts, and on such customers’ continued willingness and ability to perform their contractual obligations. We are also exposed to the credit risk of any guarantor of the customers’ obligations under their respective agreements if we must seek recourse under a guaranty. Any such credit support may not be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under an agreement resulting in a judgment in our favor where the counterparty has limited assets in the United States to satisfy such judgment, we may need to seek to enforce a final U.S. court judgment or arbitral award in a foreign tribunal, which could involve a more lengthy and less certain process and also result in additional costs.
Certain of our existing SPAs limit, and our future SPAs may limit, the liability of the relevant customer or its guarantor (or both). As a result, if a customer fails to perform its obligations under an LNG sales contract (including, for example, by failing to take or pay for the contracted volume of LNG), our ability to recover from that customer or from any guarantor of its obligations would be subject to any agreed upon limitations on liability. In
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addition, our existing SPAs excuse, and we expect that our future SPAs will excuse, performance by our customers upon the occurrence of force majeure events, such as certain severeadverse weather conditions, the breakdown or failure of its LNG tankers and acts of God.
Failures by certain of our customers to perform their obligations, or our inability to recover from such customers or the applicable guarantors, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our operating margins may be adversely affected if the price of natural gas decreases, if we pay a premium for feed gas relative to the contractual spot price we charge our customers, or as a result of inflationary pressures.
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 liquefaction fee 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.
In addition, there can be no assurance that the terms of our SPAs will pass through the actual price we pay for the supply and transport of feed gas to produce LNG under such SPAs. While we expect to manage our portfolio of gas supply to match the Henry Hub price we charge our customers under SPAs, there can be no assurance that we will be able to do so, particularly in times of volatility in the price of natural gas. If we are required to purchase feed gas at a premium relative to the Henry Hub price used to calculate the fee under the relevant LNG sales contract due to unexpected market factors or otherwise, our operating margins would be reduced.
Similarly, under certain SPAs for the sale of commissioning cargos and certain sales by VG Commodities, our customers pay a fixed fee or a fee based on an index other than Henry Hub (such as the TTF or JKM benchmarks), and in such cases our operating margins may be reduced in the event of an increase in the price at which we are required to purchase feed gas relative to the relevant fixed fee or alternate index, or in the event of a reduction in the price of the relevant index used to calculate the fee under the relevant SPA relative to the price at which we are required to purchase feed gas.
We also anticipate that certain Contracted 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 such sale 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 Contracted SPAs or certain sales by VG Commodities and, as a result, inflation may reduce our operating margins.
Any reduction in our operating margins as a result of these factors could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Natural gas producers may curtail or shut in production due to market, pricing or other conditions, which could reduce the availability of feed gas for our LNG facilities.
We depend on third-party natural gas suppliers to provide the natural gas necessary to operate our liquefaction facilities. Significant sustained declines in natural gas prices, oversupply in natural gas markets or crude, or materially adverse changes in the cost structure or profitability of upstream producers could cause producers to shut-in, curtail or reduce production from existing wells and defer or cancel planned drilling activity. Natural gas supply curtailments or shut-ins, whether due to low commodity prices, operational constraints, government actions, weather, or other market conditions, could limit the volume of natural gas available to us, and may significantly increase our feed gas costs, constrain our ability to operate our facilities at expected utilization levels, and have a material adverse effect on our business, financial condition, results of operations and future growth prospects.
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In periods of low or volatile natural gas prices, producers may elect to reduce output from higher-cost wells or delay completion of drilled but uncompleted wells, which may lead to reduced supply in the natural gas markets where we obtain our feed gas. Such supply variability could, among other things, result in increased competition for available natural gas supplies and reduced reliability of delivery commitments from suppliers. Our inability to obtain sufficient natural gas on commercially reasonable terms, or at all, could adversely affect our relationships with our customers and counterparties, who rely on us to deliver contracted volumes of LNG.
Additionally, regulatory actions, pipeline infrastructure constraints, extreme weather events, or other force majeure occurrences affecting our supply regions could exacerbate upstream production curtailments and further limit the availability of natural gas. While we seek to mitigate these risks through long-term supply arrangements, portfolio diversification and pipeline connectivity, there can be no assurance that such measures will fully protect us from the effects of upstream production slowdowns or curtailments. Any prolonged or widespread reduction in upstream natural gas production could have a material adverse effect on our business, financial condition, results of operations and future growth prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
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 Calcasieu, Plaquemines, and CP2 Projects. We will need to enter into and secure additional pipeline transportation capacity for our other future projects and and expansions, for us to generate the expected nameplate and excess capacity of LNG at such 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 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 for the Calcasieu, Plaquemines and CP2 projects, 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.
Certain metrics that we track and may present are illustrative and are subject to a number of assumptions, and any real or perceived inaccuracies in such metrics may adversely affect our business and reputation.
We track and may present from time to time certain metrics that are illustrative and not independently verified by any third party. Such metrics may be based on a range of assumptions, such as the development, completion and commissioning of the relevant projects (including obtaining any required regulatory approvals), estimated contracted
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volume for such project’s existing post-COD SPAs, assumed rate of inflation, and an assumed Henry Hub gas price per 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 our projects (including obtaining any required regulatory approvals) as described in this “Risk Factors” section. If such metrics are not 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 business and we could be subject to legal claims, including securities class action lawsuits, business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects could be affected. Our methodologies for calculating these metrics have a number of limitations and may change over time, which could result in unexpected changes to our metrics, including the metrics we publicly disclose.
We may not be successful in pursuing 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 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, expansion opportunities are subject to regulatory approval, and as of the date of this Form 10-K, we have only recently submitted applications to FERC and DOE for the Plaquemines Expansion Project and we have not otherwise made any filings with the necessary regulators, including DOE or FERC, with respect to any other expansion opportunities at our current or future projects. Such 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 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 expansions 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 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 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 expansion opportunity.
If we are not successful in pursuing 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.
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Seasonal fluctuations will cause our business and results of operations to vary among quarters, which could adversely affect our business and results of operations.
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, respectively, could have a disproportionate effect on our results of operations for the entire year. Thus, 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 useful, 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.
Our limited diversification could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Substantially all of our revenue is, and we expect will continue 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 industries, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.
In the ordinary course of our business, we explore acquisitions and other targeted investments in areas of the natural gas industry that relate to our natural gas liquefaction and export projects that could negatively affect our operating results, increase our debt or cause us to incur significant expense.
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 LNG regasification terminals in the United Kingdom and 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.
We have limited experience with pursuing such expansions of our business through acquisitions or investments, which may be in areas to our business that relate to our natural gas liquefaction and export projects. Such acquisitions or investments may expose us to new risks not presently faced by our business. If we make any acquisitions, we may not be able to integrate these acquisitions successfully into our existing business, and we could assume unknown or contingent liabilities. In addition, we may enter into agreements with counterparties outside the U.S., which would expose us to political, governmental, and economic instability, foreign currency exchange rate fluctuations and corruption risk, all of which could be exacerbated by our lack of experience doing business in such other markets. Any future acquisitions also could result in the incurrence of debt, potential violations of covenants in our debt instruments, contingent liabilities, insufficient revenue acquired to offset liabilities assumed, unexpected expenses, inadequate return of capital, regulatory or compliance issues, potential infringements, difficulties integrating such acquired companies into our operations, and other unidentified issues not discovered in due diligence or future write-offs of intangible assets or goodwill, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Integration of an acquired company also may disrupt ongoing operations and require management
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resources that we would otherwise focus on developing our existing business and projects. We may experience losses related to investments in other companies, and we may not realize the anticipated benefits of any acquisition, strategic alliance or joint venture. Accordingly, if such initiatives are not successful, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Severe weather events, hurricanes, or other disasters could result in an interruption of our operations, a delay in the completion of our projects, higher construction costs and the deferral of the dates on which we would become entitled to receive payments under any SPAs, all of which could adversely affect us.
Severe weather, including hurricanes and winter storms, can be destructive, causing construction delays, outages and property damage that require incurring additional expenses. Furthermore, our operations could be adversely affected, and our physical facilities could be at risk of damage, should changes in global climate produce, among other conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and severe weather events, abnormal levels of precipitation or a change in sea level or sea temperatures. Although the current design of each of our projects includes perimeter walls to protect against storm surge, there can be no assurance that they will be effective to protect against any of these events. In particular, all of our LNG projects that are currently under construction or development are in Southern Louisiana, which has historically been exposed to severe weather events and hurricanes. For example, in August and October 2020, respectively, Hurricanes Laura and Delta struck the Louisiana coast, with Hurricane Laura passing directly over the Calcasieu Project site.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, our projects or related infrastructure, as well as delays or cost increases in the construction and the development of our projects and following the completion of our projects, interruption of operations of our projects. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods, and rising sea levels. If any such effects were to occur, they could have a material adverse effect on our operations.
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.
Although we have obtained certain customary insurance coverage in respect of the Calcasieu, Plaquemines, and CP2 projects, 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.
We anticipate that insurance premiums for LNG projects may increase due to a continuing increase in demand by LNG projects seeking insurance coverage, and losses and claims that have arisen or been experienced in
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respect of other unrelated projects in other regions or losses and claims that are large enough to impact the broader insurance market. Furthermore, we anticipate insurance premiums for projects located in Louisiana may increase significantly following the occurrence of future major hurricane damage in the region. Changes in global climate may produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and severe weather events, abnormal levels of precipitation or a change in sea level or sea temperatures. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in further increases in insurance premiums. Any such increases in premiums could be significant and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damage.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, damage to property, fines or penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities.
Failure to retain and attract executive officers and other skilled professional and technical employees or increased labor costs could have a material adverse effect on our operations.
Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled management employees for our various business and administrative operations is high. In addition, demand for skilled professional, technical and operations employees is high in the fields of engineering, construction, operations and gas transportation. Demand for these employees is high due to growth in demand for natural gas, increased supply of natural gas as a result of developments in gas production, increased infrastructure projects, and increased regulation of these activities. There can be no assurance that we will successfully recruit or retain qualified personnel, and our inability to retain and attract these employees could adversely affect our business and future operating results.
Furthermore, while most of our executive officers are required to devote substantially all of their time to our business, if other business interests of our executive co-chairmen require them to devote substantial amounts of time elsewhere, it could limit their ability to devote time to our business which may have a negative impact on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our operating results depend in significant part upon the continued contributions of key senior management and technical personnel. Continued successful operation of our projects and management of growth requires, among other things:
• continued development of financial and management systems;
• implementation of adequate internal control over financial reporting and disclosure controls and procedures;
• hiring and training of new personnel; and
• coordination among logistical, technical, accounting, finance, information technology, administrative, and commercial personnel.
An inability to successfully manage any of these factors could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity, financing requirements and prospects.
We are dependent on the strategic direction of Michael Sabel, our Chief Executive Officer, Executive Co-Chairman of the Board and Founder, and Robert Pender, our Executive Co-Chairman, Executive Co-Chairman of the Board and Founder.
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Mr. Sabel and Mr. Pender are, through VG Partners, our controlling shareholders, and therefore have significant influence on, and are drivers of, our business planning, strategy, and culture. Our success depends to a significant degree on their leadership, long-term vision, relationships, knowledge of the industry, and ability to execute our overall business strategy. If either Mr. Sabel or Mr. Pender were to discontinue their service with us due to death, disability or any other reason, it could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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.
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. 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.
Construction, operation and maintenance of our facilities requires highly skilled personnel. There may be a limited supply of such personnel as a result of many factors, including intense competition to attract and retain the services of such persons. This competition may increase as additional LNG projects and other large-scale infrastructure projects are developed and constructed in North America, and in particular, the Gulf Coast of the United States. As a result, we and our contractors, including EPC contractors, may face shortages of qualified labor to construct, manage and operate our facilities, higher than anticipated labor costs or an inability to monitor, motivate and retain qualified personnel. An inability to recruit and retain such individuals could decrease productivity in the construction of our projects and in our operations. Competition for skilled employees could require us and our contractors, including EPC contractors, to pay higher wages, which could also result in higher labor costs.
Moreover, a shortage in the labor pool of skilled workers and other general inflationary pressures, which we and our contractors, including EPC contractors, have experienced in the past, and may continue to experience in the future, or changes in applicable laws and regulations could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We use and are planning to utilize various tax incentive programs the State of Louisiana offers that may not continue to be available or may be available in diminished form.
The State of Louisiana has various programs in place to incentivize investment in the state. These include sales tax rebates or exemptions, payroll tax credits, investment tax credits, inventory tax credits, and property tax exemptions. We have utilized such tax incentives where available for our existing projects and are planning to seek these tax benefits as well as any other tax benefits available to our other projects, including bolt-on expansions thereof. However, owing to the fiscal difficulties the state has faced in recent years, some of these programs have come under scrutiny and, as a result, the benefits provided by those programs have been reduced. In addition, applicants for these benefits have been subjected to greaterscrutiny by the state, and have been subjected to a greaterburden in demonstrating that they meet the criteria (such as job creation requirements) for the award of such benefits. Furthermore, the grant of certain of these benefits may be challenged in court.
If such lawsuits were to prevail or we are otherwise unable to secure the benefit of any of these incentive programs, or if there are further reductions to the benefits provided by these incentive programs, the financial performance and results of operations and our plans for our projects may be adversely impacted.
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Risks Relating to the LNG Industry
Competition in the LNG industry is intense, and certain of our competitors may have greater financial, engineering, marketing and other resources than we have.
We operate in the highly competitive area of LNG production, and we face intense competition from independent, technology-driven companies, national oil companies and major independent oil and natural gas companies and utilities. Certain of our competitors may have financial, engineering, marketing and other resources substantially greater than we have, and some of them are fully integrated oil and gas companies. Certain of these competitors also have longer operating histories, more development experience, greater name recognition, larger staffs, greater access to natural gas and LNG supply, and substantially greater financial, engineering, marketing and other resources than we do. In some cases, they may have also fully recouped the development and construction costs of their facilities. Our competitors’ superior resources or financial position could allow them to compete successfullyagainst us, including by increasing their LNG production, decreasing their LNG prices, offering LNG transportation or otherwise. Our ability to compete in this highly competitive environment will depend in part upon our ability to successfully develop, construct and operate our projects, including any bolt-on expansions thereof, and any other natural gas liquefaction and export facilities that we may develop in the future, and our ability to enter into SPAs or otherwise sell LNG. Increases in the production of LNG by our competitors, or decreases in their LNG prices, could have a material adverse effect on the viability of any of our planned projects and on our ability to compete with them successfully. If we are unable to compete successfully with these companies, our business, financial condition and results of operations could be adversely affected.
We face competition based upon the international market price for LNG.
Our projects are and will be subject to the risk of LNG price competition at times when we need to replace any existing post-COD SPA, whether due to natural expiration, default or otherwise, and at times when we seek to sell or enter into additional SPAs with respect to our respective projects’ commissioning cargos and LNG that is produced in excess of the volumes required under our existing SPAs. Factors relating to competition may prevent us from entering into a new or replacement post-COD SPA on economically comparable terms as existing post-COD SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our projects and any other natural gas liquefaction and export facilities that we may decide to develop in the future are diverse and include, among others:
• increases in worldwide LNG production capacity and availability of LNG for market supply;
• lower than expected global economic growth and decreased demand for energy, including LNG, or increases in demand for LNG but at levels below those required to maintain a price equilibrium with respect to the cost of supply;
• increases in the cost to supply natural gas feedstock to our projects;
• decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
• decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
• increases in capacity and utilization of nuclear power, renewable power, and related facilities outside the United States;
• political instability in foreign countries that import LNG, increased tariffs, or strained relations between such countries and the United States;
• displacement of LNG by new discoveries of gas, pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available; and
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• any events, developments or public statements, including by competitors or customers, that adversely impact our reputation.
Failure of LNG exported from the United States, including from our projects, to remain a competitive source of energy for international markets could adversely affect the LNG business of our customers, which could have a material adverse effect on their ability and willingness to perform under their Contracted SPAs with us, other sales by VG Commodities, or otherwise contract with us, and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Operations at our projects will be dependent upon the ability of our customers to deliver LNG supplies from the United States, including our projects, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan and the commercial operations of our projects, or any other natural gas liquefaction and export facility that we may decide to develop in the future, is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, increased tariffs, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the United States. Conversely, future policy change in laws or regulation in the United States could restrict or limit natural gas exports to certain countries or in general.
In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from our projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from our projects in certain markets. The cost of LNG supplies from the United States, including our projects, may also be impacted by an increase in natural gas prices in the United States. Although our customers may elect not to incur these costs by not lifting or electing not to take delivery of certain scheduled LNG cargos, they are obligated to pay the fixed liquefaction fee under the relevant SPA for their scheduled quantities. However, such commercial conditions could cause customers to seek alternatives to satisfying this obligation under their SPAs.
As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or from our projects on a commercial basis, which could have a material adverse effect on their ability and willingness to perform under their Contracted SPAs with us, other sales by VG Commodities, or contract with us with respect to the sales of our commissioning cargos or the excess capacity covered by the intercompany excess capacity SPAs. Furthermore, any such significant impediment to our customers’ ability or willingness to deliver LNG from the United States generally, or from our projects specifically, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international
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natural gas and LNG markets. In particular, changes in the price of natural gas that is supplied to our projects or any other natural gas liquefaction and export facility we may decide to develop in the future could affect the demand for, and price of, the LNG that our projects are expected to produce. Changes in the price of natural gas could also affect the competitiveness of LNG as a source of energy, which could adversely affect our customers or the demand for, and price of, LNG. Any of these factors could, in turn, affect the viability of natural gas liquefaction and export facilities such as those we are proposing to construct, and could require us to re-evaluate the viability of any of our planned projects and result in us postponing or abandoning our current plans for development of our projects. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
• competitive liquefaction capacity in North America;
• insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
• insufficient LNG tanker capacity;
• weather conditions, including temperature volatility resulting from changes in climate, and severe weather events may lead to unexpecteddistortion in the balance of international LNG supply and demand;
• reduced demand and lower prices for natural gas;
• the extent of domestic production and importation of natural gas in relevant markets;
• increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
• decreased oil and natural gas exploration activities, which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
• cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
• changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
• changes in regulatory, tax, environmental or other governmental policies (including tariffs) regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
• political conditions in natural gas producing regions, including geopolitical events such as the Russia-Ukraine conflict and the conflicts occurring in the Middle East;
• sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
• adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and
• cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent any of our counterparties is successful in any such renegotiation or termination, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated. Counterparties may also be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court.
Adverse trends or developments affecting any of these factors above could result in decreases in the price of LNG and/or natural gas, which could adversely affect the LNG business of our customers and the viability of our projects, and could also adversely affect the demand for, and price of, LNG, any of which could have a material
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adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
There may be shortages of LNG tankers worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
The construction and delivery of LNG tankers require significant capital and long construction lead times, and the availability of the tankers (including the tankers that we have contracted to acquire) could be delayed to the detriment of our LNG business and our customers, and therefore our business, because of:
• an inadequate number of shipyards constructing LNG tankers and a backlog of orders at these shipyards;
• political or economic disturbances in the countries where the vessels are being constructed or from where critical equipment is secured;
• acts of war or piracy;
• changes in governmental regulations or maritime self-regulatory organizations;
• work stoppages or other labor disturbances at the shipyards;
• bankruptcy or other financial crisis of shipbuilders or shipowners;
• quality or engineering problems;
• disruptions to maritime transportation routes;
• weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
• shortages of or delays in the receipt of necessary construction materials.
Delays in the construction and delivery of LNG tankers or other shortages in LNG tankers could result in decreases in the demand for LNG, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Technological innovation may render our anticipated competitive advantage or our processes obsolete.
Our success will depend on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, we are constructing our projects using technologies that we believe provide us with certain advantages (such as the mid-scale natural gas liquefaction trains to be supplied by Baker Hughes). However, we do not have any exclusive rights to any of the technologies that we will be utilizing, and our competitors may be planning to use similar or superior technologies.
In addition, the technologies that we are using or anticipate using in our projects may be rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others. Our existing contractual arrangements with Baker Hughes would restrict our ability to utilize any such technological advances in our projects. Moreover, any changes to the design of our projects to incorporate any such technological advances could have a negative impact on the applications we have submitted to FERC with respect to those projects. As a result, we may not be able to take advantage of any such technological advances, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Risks Relating to Our Indebtedness and Financing
Our subsidiaries have incurred a significant amount of debt and issued a significant amount of preferred equity, which could adversely affect our financial condition.
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As of December 31, 2025, our subsidiaries had approximately $34.8 billion in outstanding debt, which consisted of $11.1 billion of debt incurred or guaranteed by VGLNG and approximately $23.7 billion in project-level debt financing. As of December 31, 2025, our subsidiaries had approximately $13.5 billion of additional borrowing capacity under our existing financing agreements.
Calcasieu Funding, a subsidiary entity with equity interest in the Calcasieu Project, has issued preferred units for total gross proceeds of $900 million, with an aggregate liquidation preference of approximately $1.7 billion outstanding as of December 31, 2025, some of which require us to make preferential cash distributions to the holders under certain circumstances.
VGLNG also issued 9.000% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share, or the VGLNG Series A Preferred Shares, which are entitled to preferential cash distributions, with an aggregate liquidation preference of $3.0 billion outstanding as of December 31, 2025.
This substantial amount of indebtedness and preferred equity could have important consequences to us, including:
• making it more difficult for us to satisfy our obligations with respect to our existing debt and our subsidiaries’ existing preferred equity;
• limiting our ability, or increasing the costs, to refinance our indebtedness;
• limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy or other purposes;
• limiting our ability to use our cash and capital resources in other areas of our business because we must dedicate a substantial portion of these funds to service debt and preferred equity;
• increasing our vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness that bears interest at variable rates;
• limiting our ability to react to changing market conditions in our industry, to our customers’ businesses and to economic downturns;
• limiting our ability to attract future customers for SPAs in connection with any expansion of our facilities compared with other companies that may have substantially less debt;
• limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;
• limiting our ability to capitalize on business opportunities and to react to competitive pressures; and
• resulting in a material adverse effect on our business, operating results and financial condition if we are unable to service our indebtedness or obtain additional capital, as needed.
Under the terms of certain agreements governing our indebtedness, we are permitted to incur additional indebtedness, which could further accentuate these risks.
Servicing our indebtedness and preferred equity will require a significant amount of cash and we may not have sufficient cash, operating cash flows and capital resources to service our existing and future indebtedness and preferred equity.
We may be required to use a substantial portion of our cash and capital resources to pay interest and principal on our indebtedness, as well as cash distributions or other required payments on preferred equity of our subsidiaries. Such payments may reduce the funds available to us to construct and complete the Plaquemines Project, the CP2 Project, or any expansion of our projects or other natural gas liquefaction and export facility we may develop, to acquire our LNG tankers, and for working capital, capital expenditures, and other corporate purposes, and limit our
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ability to obtain additional financing. This may in turn limit our ability to implement our business strategy, heighten our vulnerability to downturns in our business, the industry or in the general economy, and limit our flexibility in planning for, or reacting to, changes in our business and the industry.
We may not have sufficient cash, operating cash flows and capital resources to service our existing and future indebtedness and preferred equity. As of December 31, 2025, our material sales and operating cash flow has been limited to sales of LNG from our Calcasieu Project (including short-term sales of commissioning cargos, sales under our post-COD SPAs, and sales of LNG from excess capacity) and the short-term sales of LNG commissioning cargos from the Plaquemines Project prior to commencing commercial operations. We cannot assure you when we will begin to generate any operating cash flow from commercial operations at the Plaquemines Project, the CP2 Project or any bolt-on expansions thereof or any of our future projects. Our ability to service our debt and preferred equity will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, political, regulatory and other factors, some of which are beyond our control. We also cannot assure you that our business will generate sufficient cash flow from operations or that future financing will be available to us in amounts sufficient to enable us to make required and timely payments on our indebtedness or preferred equity, or to fund our operations.
If we face such liquidity problems, we could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness or preferred equity. We may not be able to effect any such alternative measures, if necessary, on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to make required payments on our indebtedness or preferred equity. In addition, certain agreements governing our existing indebtedness and preferred equity and the terms of such future agreements or preferred equity may also restrict our ability to raise debt or equity capital to be used to repay our existing indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to make required payments on our indebtedness or preferred equity when due. If our cash, operating cash flows and capital resources are insufficient to fund those obligations, it could result in an event of default under such indebtedness, which, if not cured or waived, could result in the acceleration of all or a portion of our debt. As a result, our debtholders would be entitled to proceed to forecloseagainst all collateral that secures such debt, representing substantially all assets of the relevant project. In addition, if the distributions on preferred units issued by Calcasieu Funding are made in the form of an increase in the funding face value instead of in cash for six consecutive calendar quarters with the first full quarter following the commencement of commercial operations of the Calcasieu Project, certain investors may exercise step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project.
As a holding company, the Company depends on the ability of its subsidiaries to transfer funds to it to meet its obligations.
The Company is a holding company for all of our operations and is a legal entity separate from its subsidiaries. As a result, the Company is dependent on the ability of its subsidiaries to make loans, pay dividends and make other payments to generate the funds necessary for the Company to meet its financial obligations and to pay dividends to stockholders, if any. The inability to receive dividends from its subsidiaries could have a material adverse effect on our business, financial condition, cash flows and results of operations. In particular, following COD of the Calcasieu Project, but prior to August 19, 2027, no distributions from Calcasieu Funding to VGLNG, its indirect parent, are permitted until Calcasieu Funding has redeemed in cash any accrued distributions on its preferred units, which are owned by a third party. Furthermore on and after August 19, 2027, no distributions from Calcasieu Funding to VGLNG are permitted until Calcasieu Funding has redeemed in cash all of such preferred units.
The subsidiaries of the Company have no obligation to pay amounts due on any liabilities of the Company or to make funds available to the Company for such payments. The ability of our subsidiaries to pay dividends or other distributions to the Company in the future will depend, among other things, on their earnings, tax considerations and covenants contained in any financing or other agreements, such as the covenants governing our subsidiaries’ current indebtedness and preferred equity. In particular, our subsidiaries may incur additional indebtedness or issue
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additional preferred equity that may restrict or prohibit the making of distributions, the paying of dividends or the making of loans by such subsidiaries to the Company. In addition, such payments may be limited as a result of claimsagainst the Company’s subsidiaries by their creditors, including suppliers, vendors, lessors and employees.
If the ability of the Company’s subsidiaries to pay dividends or make other distributions or payments to the Company is materially restricted by cash needs, bankruptcy or insolvency, or is limited due to operating results or other factors, we may be required to raise cash through the incurrence of debt, the issuance of equity or the sale of assets. However, there is no assurance that we would be able to raise sufficient cash by these means. This could have an adverse effect on the Company’s ability to pay its obligations or pay dividends, if any, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred equity of our subsidiaries also gives the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities or paying dividends to the Company.
Our debt agreements contain various covenants restricting the ability of certain of our subsidiaries to, among other things:
• incur or guarantee additional debt or issue disqualified stock or preferred stock;
• pay dividends (including to the Company) and make other distributions on, or redeem or repurchase, capital stock;
• make certain investments;
• incur certain liens;
• enter into transactions with affiliates;
• merge or consolidate;
• enter into agreements that restrict the ability of restricted subsidiaries to make dividends or other payments to the issuers;
• designate restricted subsidiaries as unrestricted subsidiaries; and
• transfer or sell assets.
In addition, our project financing credit agreements require our projects to maintain certain historical debt service coverage ratios, respective to each project and upon achieving certain milestones.
The holders of Class B common units of Calcasieu Holdings have the right to select and appoint one manager to the board of managers of Calcasieu Holdings, and such manager’s consent is required, among others, prior to:
• amending key project contracts;
• incurring any additional indebtedness in excess of $75.0 million, subject to certain exceptions; and
• issuing or redeeming equity under certain circumstances.
In addition, other than Venture Global Calcasieu Pass Holding, LLC contributing capital in exchange for issuance of common units in Calcasieu Funding, Calcasieu Funding may not issue additional units without a majority approval of holders of its preferred units.
Moreover, the agreements governing the VGLNG Senior Secured Notes and the VGLNG Revolving Credit Facility contain various covenants restricting the ability of certain of our subsidiaries to, among other things:
• incur or guarantee additional indebtedness or issue disqualified stock or certain preferred stock;
• pay dividends and make other distributions or repurchase stock;
• create or incur certain liens;
• merge, consolidate or transfer or sell all or substantially all of their assets; and
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In addition, the terms of the VGLNG Revolving Credit Facility require us to maintain a maximum total leverage ratio of no more than 6.00:1.00.
Our failure to comply with the restrictive covenants described above as well as other terms of our other indebtedness and/or the terms of any future indebtedness from time to time could result in an event of default, which, if not cured or waived, could result in our being required to repay these borrowings before their due date. If we are forced to refinance these borrowings on less favorable terms or are unable to refinance these borrowings, there could be a material adverse effect on our business, financial condition and results of operations.
Additionally, if VGLNG does not pay semi-annual dividends on the VGLNG Series A Preferred Shares, certain terms of the VGLNG Series A Preferred Shares restrict VGLNG’s ability to pay dividends, repurchase its common stock, or issue certain types of securities. Furthermore, when any dividends on any VGLNG Series A Preferred Shares are in arrears for three or more consecutive semi-annual dividend periods, VGLNG is required to increase the number of members of its board of directors by two, until such time as all accrued dividends for all past dividend periods have been fully paid.
As a result of these restrictions, we will be limited as to how we conduct our business and we may be unable to raise additional debt or equity financing to compete effectively, distribute cash from our subsidiaries to the Company, or take advantage of new business opportunities. The terms of any future indebtedness we may incur or equity financing we may raise could include more restrictive covenants. We cannot assure you that we will be able to maintain compliance with these covenants in the future and, if we fail to do so, that we will be able to obtain waivers from the relevant lenders or holders and/or amend these covenants.
Increases in interest rates would increase the cost of servicing our debt and could reduce our profitability.
The debt outstanding under certain of our credit facilities bears interest at variable rates. While a substantial portion of such debt has been hedged to a fixed rate with interest rate swaps, increases in interest rates would increase the cost of servicing our subsidiaries’ debt, even if the amount borrowed remains the same, and could materially reduce our consolidated profitability and cash flows. As a result of such increases in the cost of servicing our subsidiaries’ debt, our subsidiaries may be unable to make distributions to us.
The U.S. Federal Reserve Board significantly increased the federal funds rate in 2022 and 2023, which led to an increase in the borrowing costs on our variable rate debt. While the U.S. Federal Reserve has recently began lowering the federal funds rate (which had a corresponding impact on our borrowing costs), we cannot assure you that the U.S. Federal Reserve will continue to reduce the federal funds rate in the future or whether it will increase such rate. Any future federal funds rate increases could in turn make our financing activities more costly and limit our ability to refinance existing debt when it matures or pay higher interest rates upon refinancing and increase interest expense on refinanced indebtedness. Any federal funds rate increases could in turn make our financing activities more costly and limit our ability to refinance existing debt when it matures or pay higher interest rates upon refinancing and increase interest expense on refinanced indebtedness.
Despite the current level of indebtedness and preferred equity issued by our subsidiaries, we expect to incur significant additional debt, some or all of which may be secured, and equity financing to fund the development, construction and completion of our projects. This could further exacerbate the risks to our financial condition described above.
Although we are subject to certain limitations on additional indebtedness and equity financing pursuant to the terms of agreements governing our existing indebtedness and preferred equity, these restrictions are subject to a number of qualifications and exceptions, and additional indebtedness and/or preferred equity incurred in compliance with these restrictions could be substantial. We expect to incur significant additional debt and equity financing to fund the development, construction and completion of the CP2 Project, any potential bolt-on expansions and any other natural gas liquefaction and export facilities, or other projects, that we may decide to develop in the future. As of December 31, 2025, our subsidiaries had approximately $13.5 billion of additional borrowing capacity in the form of available commitments (all of which would have been secured).
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To the extent we or any of our subsidiaries incurs or issues additional debt and/or preferred equity, as applicable, the risks described in the preceding risk factors would increase.
Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.
If we are unable to fund our debt service obligations or comply with restrictive covenants under our existing or future indebtedness, it could result in an event of default under such indebtedness which, if not cured or waived, could result in the acceleration of some or all of our debt. If we are unable to repay those amounts, our lenders and the holders of our debt securities could proceed to forecloseagainst the collateral securing such indebtedness. Any such foreclosure could have a material adverse impact on our business, financial condition, cash flows and results of operations.
In particular, we granted holders of the VGLNG Senior Secured Notes and the lenders under the VGLNG Revolving Credit Facility a first-priority lien in substantially all of the existing and future assets of VGLNG, including the direct wholly-owned subsidiaries of VGLNG that directly or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, any future projects and any related pipeline. Additionally, we granted certain of our lenders under the Calcasieu Pass Credit Facilities and holders of the VGCP Senior Secured Notes: (i) a first-priority perfected security interest in substantially all of VGCP’s and TCP’s existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of VGCP, including, without limitation, the Calcasieu Project site; (iii) a first-priority perfected security interest in 100% of the equity interests in certain subsidiaries relating to the Calcasieu Project; and (iv) all proceeds of the foregoing as collateral. In addition, Calcasieu Pass Pledgor, LLC granted the lenders and holders of the VGCP Senior Secured Notes a first-priority perfected security interest in all of the equity interests in VGCP and TCP. We also granted certain of our lenders under the Plaquemines Credit Facilities and holders of the VGPL Senior Secured Notes: (i) a first-priority perfected security interest in substantially all of Plaquemines’ and Gator Express’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of Plaquemines, including, without limitation, the Plaquemines Project site; (iii) 100% of the membership interests in Plaquemines and Gator Express; and (iv) all proceeds of the foregoing as collateral. We granted certain of our lenders under the CP2 Credit Facilities: (i) a first-priority perfected security interest in substantially all of CP2's and CP Express’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of CP2, including, without limitation, the CP2 Project site; (iii) 100% of the membership interests in CP2 and CP Express; and (iv) all proceeds of the foregoing as collateral. Further, we granted certain of our lenders under the CP2 EBL Facility (i) a first-priority perfected security interest in substantially all of CP2 Holdings’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) 100% of the membership interests in CP2 Holdings; and (iii) all proceeds of the foregoing as collateral. Furthermore, we granted certain of our lenders under the Blackfin Credit Facilities: (i) a first-priority perfected security interest in substantially all of Blackfin Pipeline, LLC's and Blackfin Supply, LLC's existing and after-acquired personal property including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on certain material real property interests of Blackfin Pipeline, LLC, and Blackfin, Supply, LLC; (iii) a first-priority perfected security interest in 100% of the equity interests in Blackfin Pipeline, LLC and Blackfin Supply, LLC; and (iv) all proceeds of the foregoing as collateral. As a result, the creditors under any such indebtedness could proceed to forecloseagainst such collateral securing the applicable indebtedness following an event of default, which would have a material adverse impact on our business, financial condition, cash flows and results of operations.
In addition, the holders of Class B units in Calcasieu Holdings, or the Investors, will have the right to appoint a majority of the board of managers of Calcasieu Holdings, or the Step-In Right, upon the occurrence of certain trigger events. Such trigger events include if an event of default occurs under the Calcasieu Pass Credit Facilities
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and if certain distributions continue to accrue at Calcasieu Funding after COD. Because Calcasieu Holdings is the sole member of the entity that wholly owns the Calcasieu Project and the TransCameron Pipeline, the Step-In Right not only gives the Investors significant control over Calcasieu Holdings but also over the Calcasieu Project and the TransCameron Pipeline. The Investors’ interests may differ from our interests or those of our stockholders, and therefore the Investors may not always exercise the control in a way that benefits us or our stockholders, which may have a negative impact on our business, financial conditions and results of operations.
Our use of hedging arrangements may adversely affect our future operating results or liquidity.
To help mitigate our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we may use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange, or the NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Any hedging arrangements would expose us to risk of financial loss in some circumstances, including when:
• expected supply is less than the amount hedged;
• the counterparty to the hedging contract defaults on its contractual obligations; or
• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other non-U.S. regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.
The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the OTC derivatives market, and entities like us that participate in that market, may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities.
CFTC position limits rules restrict the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. The application of these requirements affect the overall derivatives market, including the costs and availability of the types of swaps we use to hedge or mitigate our commercial risks.
Under the CEA and the rules adopted thereunder, certain swaps may be required to be cleared through a DCO. While the CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, it has not yet adopted rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Further, we qualify for and rely on the end-user exception from the mandatory clearing and trade execution requirements for any swaps entered into to hedge our commercial risks. If we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a DCO, we could be required to post margin (or post higher margin than if we entered into an uncleared OTC swap) with respect to such swap, our cost of entering into and maintaining such swap could increase, and we would not enjoy the same flexibility with the terms of the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as our counterparties, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.
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For uncleared swaps, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. In addition, some of our counterparties are subject to the regulations imposing capital requirements on them, which may increase the cost to us of entering into swaps with them because, although not required to collect margin from us under the margin rules, our counterparties may contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.
While we are directly subject to only limited regulatory requirements for our derivatives, the application of these requirements to other market participants, including our counterparties, may affect the overall swaps market, including the costs and availability of swaps we may use to hedge or mitigate our risks. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, our operating results and cash flows may become more volatile and could be otherwise adversely affected.
The Federal Reserve Board also has proposed rules that would limit certain physical commodity activities of financial holding companies. Such rules, if adopted, may adversely affect our ability to execute our strategies by restricting our available counterparties for certain types of transactions, limiting our ability to obtain certain services, and reducing liquidity in physical and financial markets. It is uncertain at this time whether, when and in what form the Federal Reserve Board’s proposed rules regarding physical commodity activities of financial holding companies may become final and effective.
European and UK-specific regulations, including but not limited to EMIR, MiFID II, REMIT, MAR, FSMA and the RAO, govern our trading activities and our compliance with such laws may result in increased costs and risks to the business similar to the impacts stated above with respect to the Dodd-Frank Act. The increased costs may also have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Further, any violation of the foregoing laws and regulations could result in investigations, and possible fines and penalties, and in some scenarios, criminal offenses.
Further, the potential for divergence between the UK and EU financial regulatory regimes following the UK’s withdrawal from the EU, has created uncertainty among market participants and may result in additional regulatory risks and compliance costs. While it is expected that the UK will maintain regulatory standards similar to those in the EU, technical differences have emerged recently and it is likely that this trend will continue to increase over time.
We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight, and the ultimate effect on our business of any future changes to this regulatory regime remains uncertain.
Risks Relating to Regulation and Litigation
We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.
The design, construction and operation of the facilities constituting our projects, as well as the export of LNG and the transportation of natural gas, are highly regulated activities. Certain of our projects remain subject to the application for and/or receipt of several material federal, state and local governmental and regulatory approvals and permits, as described further under Item 1.— Business — Governmental Regulation of this Form 10-K. Approvals of FERC and DOE under Sections 3 and 7 of the Natural Gas Act, or the NGA, as well as several other material governmental and regulatory approvals and permits, including under the Clean Air Act, or the CAA, and the Clean Water Act, or the CWA, are required in order to construct and operate an LNG facility and a natural gas pipeline,
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and to export the LNG produced at our projects. See also Item 1.— Business — Environmental Regulation of this Form 10-K. Our projects that have obtained needed approvals and permits remain subject to extensive regulation.
The authorizations obtained from FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and such agencies may impose additional approval and permit requirements. DOE has stated that it has authority to amend, modify, or revoke existing LNG export authorizations issued pursuant to Section 3 of the NGA if necessary or appropriate to protect the public interest. In addition, the DOE may suspend or revoke our export authorizations if we, our customers, and/or their downstream customers, do not comply with the terms and conditions of the authorizations or if the DOE later determines that LNG exports are contrary to the public interest.
On January 20, 2025, President Trump issued an Executive Order entitled “Unleashing American Energy,” that, among other provisions, directed DOE to restart reviews of applications for approvals of LNG exports and directed the consideration of the economic and employment impacts to the U.S. and the impact to the security of allies and partners that would result from granting the application. Other parts of the wide-ranging Executive Order require expedited permitting and elimination of delays and revoke prior executive orders related to the CEQ and greenhouse gas ("GHG") emissions. A second Executive Order issued that same day declared a “National Energy Emergency” and, among other things, recognized the benefits of selling LNG to international allies and partners. On January 21, 2025, DOE directed to the Office of Fossil Energy and Carbon Management to resume consideration of pending applications for LNG exports in accordance with the Natural Gas Act and extended the comment period on the DOE study to March 20, 2025 “to ensure such public interest determinations receive appropriate stakeholder input.” The first Secretarial Order issued by DOE Secretary Wright on February 5, 2025, stated that DOE has resumed consideration of pending export authorizations and will identify and exercise its legal authorities to expedite the approval and construction of reliable energy infrastructure.
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 the public interest. Since that date, DOE has issued a series of orders authorizing US LNG exports, including certain orders for our projects. 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 our related contracts.
While FERC has authorized the siting, construction and operation of the Calcasieu Project, the Plaquemines Project and the CP2 Project, as well as of the related pipelines, under Sections 3 and 7 of the NGA, additional authorizations from the Commission and/or staff of FERC, as applicable, are still needed as part of FERC’s ongoing regulation of our projects. Such implementation authorizations are required to complete the construction and commissioning of the Plaquemines Project and place its facilities into commercial service, and similar authorizations will be needed throughout the construction and commissioning of the CP2 Project.
We have other planned projects that have not yet received required authorizations from FERC or DOE. We have recently filed for, but not yet obtained, authorizations for certain projects such as Plaquemines Expansion Project and our requests to increase the authorized output of the existing Plaquemines Project and the CP2 Project without adding any new facilities. We have not yet made any filings to the FERC or DOE regarding any other future project or any expansions. As we proceed with our efforts to obtain regulatory approvals for such projects, we may face additional regulatory risks or delays from time to time as they are based on various factors outside of our control. There can be no assurance that regulatory risks or issues from FERC or other regulatory agencies will not interfere with our prevent our plans to develop these additional projects.
We cannot predict whether our applications, approvals or permits will attract significant opposition or whether the permitting process will be lengthened due to complexities and appeals, including uncertainty and delays in the timetable on which the DOE will authorize increases in the expected annualized peak liquefaction capacity for the Plaquemines Project and exports from, the Plaquemines Expansion Project, as well as for the FERC and DOE to act on future applications for our other future projects or expansions, litigation by environmental groups and other advocates concerned about the impact of our projects on climate change and pollution as well as resistance by local communities due to environmental, health and safety concerns. A number of environmental groups have actively
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opposed the regulatory approvals necessary for our projects, including by pursuing appeals of authorizations we have received for the CP2 Project. See — Risks Relating to Our Project and Other Assets — Various economic and political factors, including opposition by environmental or other public interest groups, could negatively affect the timing or overall development, construction and operation of our projects, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Opposition to our projects from environmental groups and other advocates may increase and strengthen over time. Any appeal of or litigation relating to our permits or approvals may delay the development of our natural gas liquefaction and export facilities. There can be no assurance that any opposition, appeals or other litigation, will not be successful or not delay our ability to develop the CP2 Project, or any other future projects or expansions we may seek to develop.
We do not know whether or when any of the approvals or permits we require can be obtained, whether any existing or potential future interventions or other actions by third parties will interfere with our ability to obtain and maintain such approvals or permits, whether any such approvals and permits may be revoked or altered in the future, or whether we will be able to comply with the conditions or requirements that such approvals or permits might impose. In addition, requests by regulators for additional information or additional regulatory submissions may delay the regulatory approval process and may also lead to changes in our project design. There is no assurance that we will obtain and maintain these governmental approvals and permits, or that we will be able to obtain them on a timely basis.
The denial of an application, approval or permit essential to a project or bolt-on expansion opportunity or the imposition of impractical conditions would impair our ability to develop a project or bolt-on expansion opportunity. Similarly, a delay in the review and permitting process for our projects or bolt-on expansion opportunities could impair or delay our ability to develop the relevant project or bolt-on expansion opportunity or increase the cost so substantially that the relevant project or bolt-on expansion opportunity is no longer financially attractive to us. Certain of the foregoing approvals and permits must be obtained before construction of a particular project or bolt-on opportunity can begin, and before we can pursue any additional potential bolt-on expansion opportunities at such projects. If we are unable to obtain and maintain the necessary approvals and permits or satisfy additional permit requirements imposed on us, we may not be able to complete our projects on schedule or operate them and provide services to our customers under the SPAs and, consequently, a failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
In the future, additional regulatory approvals may be required or significant costs may be incurred due to delays caused by the opposition, changes in laws and regulations or for other reasons. In addition, zoning, environmental, health and safety laws and regulations are subject to periodic amendment or promulgation and may become more stringent over time. Accordingly, we cannot assure that such laws or regulations will not be changed or reinterpreted or that new laws or regulations will not be adopted. The costs of complying with future laws and regulations may require us to incur materially higher costs.
There can be no assurance that our existing or future regulatory approvals will not be subject to other legal challenges, or that such approvals will not be re-examined vacated, withdrawn, overturned, altered or otherwise modified in a manner adverse to the development, construction or operation of one or more of our projects or to our business more generally. If we are required to modify our activities as a result of any changes to our existing regulatory approvals, the impact could increase our project costs, delay our project timelines, affect our ability to complete our planned projects, or result in claims from third parties if we are unable to meet our commitments under our pre-existing commercial agreements, all of which could have a material adverse effect on our business.
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Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation.
Our natural gas pipelines providing interstate transportation are subject to regulation by FERC under the NGA and under the Natural Gas Policy Act of 1978, or the NGPA. FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If our interstate natural gas pipelines fail to comply with all applicable statutes, rules, regulations and orders, they could be subject to substantial penalties and fines.
As our interstate natural gas pipelines are subject to FERC regulations, we must file FERC gas tariffs, as well as any subsequent changes to the filed FERC gas tariffs or agreements related to the pipelines from time to time, with FERC for approval for each of our pipelines. We have currently effective tariffs in place for our TransCameron and Gator Express pipelines, and any changes to those tariffs would require FERC approval. The construction and operation of any new, modified, or expanded facilities on our pipelines may also require FERC authorization. There can be no assurance that FERC will accept such filings on anticipated terms and timelines, or at all.
Should we, or any of our applicable subsidiaries that own a FERC-jurisdictional pipeline fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we or such subsidiary could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for violations of currently up to approximately $1.58 million (with future changes indexed to inflation) per day for each violation.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The Pipeline and Hazardous Materials Safety Administration, or PHMSA, has exclusive authority to establish and enforce safety regulations for onshore LNG facilities and pipelines transporting hazardous materials such as natural gas. PHMSA periodically inspects LNG facilities and operators to enforce compliance with the applicable safety regulations. During the inspections, PHMSA reviews operator records to determine if facility equipment has been properly maintained and if the operator has developed and follows operation, maintenance, security, and emergency procedures that ensure the continued safe operation of the facility. Compliance with PHMSA requirements, which may change over time, can impose additional costs or liabilities on us or adversely affect our operations. PHMSA enforces violations it finds, which can include civil penalties or orders directing action. In addition, if PHMSA finds conditions that are hazardous, it can require the shut-down of the relevant facilities and expeditious corrections of the conditions through corrective action orders.
PHMSA also requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
• perform ongoing assessments of pipeline integrity;
• identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;
• improve data collection, integrate and analyze pipeline data;
• repair and remediate the pipeline as necessary; and
• implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. PHMSA has authority to impose administrative fines and penalties for violations of its safety standards, and such violations may also give rise to civil enforcement actions.
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In addition, the costs of compliance with integrity management programs and other PHMSA requirements may be difficult to predict. Furthermore, these standards are subject to regular statutory and regulatory revision and generally have become more stringent over time, as PHMSA promulgates new or revised regulations and as Congress amends existing pipeline safety laws. If these standards become more stringent in the future, it could cause us, like other similarly situated pipeline operators, to incur increased costs for operating our pipelines, to incur increased costs for developing future projects or bolt-on expansion opportunities, or to suffer potential adverse impacts to our operations. For instance, on January 17, 2025, PHMSA issued a final rulemaking implementing a mandate under the Protecting Our Infrastructure and Enhancing Safety Act of 2020, or the PIPES Act, to reduce methane emissions from new and existing natural gas transmission, regulated gathering and distribution pipelines, natural gas storage, and LNG facilities. The rule imposes enhanced leak survey and patrolling requirements, standards for leak detection programs, leak grading and repair criteria, repair timelines, requirements for mitigation of emissions from blowdowns, requirements for investigatingfailures, and criteria for the design, configuration and maintenance of pressure relief devices. However, the rule was not published in the Federal Register prior to a regulatory freeze issued by the Trump administration on January 20, 2025 and therefore has not taken effect. Any future rule implementing these mandates under PIPES Act may require operators of pipelines and facilities to make operational changes or modifications at their facilities to meet standards beyond current requirements. In May 2025, PHMSA issued two Advance Notices of Proposed Rulemaking (“ANPRM”) seeking public comment on updates to its safety regulations for pipelines and LNG facilities aimed at implementing the President’s “Unleashing American Energy” Executive Order. In June 2025, PHMSA issued another ANPRM to solicit stakeholder feedback on whether to repeal or amend any requirements in its pipeline safety regulations to eliminate undueburdens on the identification, development, and use of domestic energy resources and to improve government efficiency. The ultimate impact of those efforts of the Trump Administration remains to be seen. If safety standards were to become more stringent in the future, it could cause us, like other similarly situated companies, to make changes or modifications at our facilities that may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Any repair, remediation or delayed remediation, preventative or mitigating actions may require significant capital and operating expenditures and may subject us to significant reputational or financial risk. Should we fail to comply with applicable statutes and the PHMSA rules and related regulations and orders, we could be subject to significant penalties and fines, which would have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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.
Our business is and will be subject to extensive federal, state and local laws and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste, and petroleum products; and investigation and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, Oil Pollution Act, or OPA, CWA, Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and Resource Conservation and Recovery Act, or RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our projects and any other natural gas liquefaction and export facility we may decide to develop in the future, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and to provide reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our projects and related pipelines, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, operational or construction restrictions, difficulty obtaining and maintaining permits from regulatory agencies or capital expenditures and operational costs related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of the proposed liquefaction facilities, we could be liable for the costs of investigating and cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources, including as they relate to releases of hazardous substances that pre-date our possession and operation.
We have conducted Phase I environmental studies on all of our project sites, and from time to time we have encountered environmental conditions on certain sites that we may be required to monitor or address prior to making use of the relevant project site. In addition, future studies and analyses may reveal adverse environmental conditions on them of which we are not currently aware, and we may be required to investigate and remediate such conditions or make other changes to those sites. Any discovery of preexisting, or occurrence of new, environmental conditions that require remediation or other alterations to our current plans for our projects could delay or prevent the construction of that project, or require us to pay penalties or fines or otherwise incur significant losses and liabilities, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Federal and state regulatory authorities have pursued regulatory and policy initiatives to reduce GHG emissions in the United States from a variety of sources, but such initiatives continue to be controversial and subject to frequent changes and revisions depending on legal and political developments. For example, on December 15, 2009, the Environmental Protection Agency, or the EPA, published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment, which provided legal support for EPA to pursue GHG emissions regulations under the Clean Air Act. However, on August 1, 2025, the EPA issued a proposed rule that would rescind these findings. In addition, in May 2024, the EPA finalized a new rule regulating GHG emissions from the power sector that would phase in requirements for certain fossil fuel-fired power plants to implement GHG reduction methods, including, among other things, the installation of systems to capture and sequester their carbon emissions. This rule is the subject of legal challenges pending before the Court of Appeals for the District of Columbia, as well as, a June 2025 EPA proposal that would repeal it. We cannot predict the outcome of these developments.
On December 2, 2023, EPA issued a final rule updating and broadening requirements for new, modified, and reconstructed oil and gas sources, including oil and gas wells, controllers, pumps, storage vessels, and compressor stations aimed at reducing methane and volatile organic compound emissions and directing states to develop plans largely paralleling these requirements for hundreds of thousands of existing oil and gas sources. The rule also includes a Super-Emitter Response Program, whereby qualified third parties may document super-emitter events and notify owners or operators of affected sites, requiring them to investigate and take measures to mitigate methane emissions. This rule is subject to pending legal challenges in the Court of Appeals for the District of Columbia as well. On January 20, 2025, President Trump signed an Executive Order to once again withdraw the U.S. from the Paris Agreement as well as a wide-ranging Executive Order entitled “Unleashing American Energy,” that, among other provisions, directed all agencies to adhere to only relevant legislated requirements for environmental considerations and to prioritize energy production. The future impact of these actions, and the current U.S. administration generally, on GHG emissions and climate-related regulations and initiatives cannot be predicted at this time.
Section 60113 of the Inflation Reduction Act, which was signed into law on August 16, 2022, establishes a charge on excess methane emissions from various facilities operating in the oil and gas sector, including liquefied natural gas storage and liquefied natural gas import and export equipment, that report more than 25,000 metric tons of carbon dioxide equivalent emissions per year. For liquefied natural gas facilities, the excess emissions charge is based on the reported tons of methane emissions that exceed 0.05 percent of the natural gas sent to sale from or through such facilities. We anticipate that our facilities would be subject to such excess emissions charge. In March 2025, President Trump signed a measure passed by Congress to repeal the EPA rule implementing the emissions charge. On July 4, 2025, President Trump signed the One Big Beautiful Bill Act, which, among other things, postpones the EPA’s imposition of the emissions charge until 2034. The future prospects of the emissions charge remain uncertain.
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The United States Congress has from time to time considered other legislation to restrict or regulate emissions of GHGs. The United States Congress has from time to time considered other legislation to restrict or regulate emissions of GHGs, including energy legislation or other initiatives that seek to address GHG emissions issues or restrict oil and gas operations. In addition to the uncertainties in federal climate policy, we could still be subject to or impacted by international initiatives, state initiatives or by future federal regulatory initiatives, which could include direct GHG emissions regulations, a carbon emissions tax, or cap-and-trade programs. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.
Other federal and state initiatives, as well as initiatives in foreign jurisdictions where we intend to market our products, have been implemented, are being considered or may be considered in the future to address GHG emissions and other climate and environmental concerns. These may include, but are not limited to, treaty commitments, direct regulation, carbon emissions taxes, cap and trade programs or mandates to the power sector to incorporate certain percentages of renewable energy into their portfolio. For example, the EU has adopted a legally binding target of net zero GHG emissions by 2050. Additionally, in August 2024, an EU regulation went into effect that is aimed at reducing methane emissions associated with natural gas, oil and coal imports and imposes monitoring, reporting and verification standards on importers of fossil fuels into the EU with respect to the “life cycle” methane emissions associated with the products. Certain initial reporting requirements commenced in 2025, and reporting requirements for importers to demonstrate that imports were produced in accordance with monitoring, reporting and verification standards equivalent to EU requirements will take effect in 2027. EU authorities are in the process of developing rules for importers to demonstrate equivalency under the regulation. In addition, the U.S. administration has been lobbying the EU to exempt U.S. companies from the regulation until 2035. The ultimate scope of this regulation, including the outcome of lobbying efforts for U.S. exemptions, and the impact on our compliance, reporting and operational costs, and the marketability of our imports, remains uncertain.
In addition, from time to time, proposals have been made to change the way FERC considers GHG emissions in reviewing applications under the National Environmental Policy Act, or NEPA, and the NGA. For example, in January 2025, FERC withdrew its draft interim policy statement for consideration of GHG emissions in natural gas infrastructure reviews, stating that impacts associated with GHG emissions would be considered on a case-by-case basis. In May 2024, the CEQ published final “Phase 2” NEPA regulations which included specific direction to account for both climate change and environmental justice effects in NEPA reviews. However, these regulations were ultimately rescinded by CEQ in 2025. In May 2025, CEQ also withdraw previous interim guidance intended to assist agencies in their consideration of the effects of GHG emissions and climate change in NEPA review. While the ultimate scope and content of GHG emissions and climate-related analysis in NEPA reviews remains uncertain, any future initiatives or proposals to include such considerations could affect the demand for, or the availability or cost of, natural gas, which we consume at our terminals, or could increase compliance costs for our operations.
GHG emissions (such as carbon dioxide and methane) that could be regulated include, among others, those associated with our power generation, liquefaction and transportation of natural gas, and consumers’ or customers’ use of our products. Many of these activities, such as consumers’ and customers’ use of our products, as well as actions taken by our competitors in response to such laws and regulations, are beyond our control. Attention to climate change risks has also resulted and may continue to result in private initiatives by certain members of the investment community as well as public interest groups aimed at discouraging the production, development and consumption of fossil fuels.
GHG emissions-related laws and related regulations, consumer and investor preferences with respect to fossil fuels and the effects of operating in a potentially carbon-constrained environment may result in substantially increased capital, compliance, operating and maintenance costs and could, among other things, reduce demand for LNG, make our products more expensive and adversely affect our sales volumes, revenues and margins.
The ultimate effect of international agreements and national, regional and state legislation and regulatory measures to limit GHG emissions on our financial performance, and the timing of these effects, will depend on numerous factors. Such factors include, among others, the sectors covered, the GHG emissions reductions required
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and the extent to which we are able to recover the costs incurred through the pricing of our products in the competitive marketplace. Further, the ultimate impact of GHG emissions-related agreements, legislation, regulations, or private initiatives on our financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes and the timing thereof.
Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from our projects, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We are involved, and may in the future become involved, in disputes and legal proceedings.
We are involved, and may in the future become involved, in disputes as well as legal proceedings with public authorities, shareholders, suppliers, contractors, customers, land-owners, current or former employees, and others. Given the nature of our business, such disputes and legal proceedings often involve highly complex legal and factual questions and determinations and, in some cases, introduce significant levels of exposure.
For example, the Calcasieu Project is currently involved in arbitration proceedings with certain of its customers under post-COD SPAs related to the Calcasieu Project as described in more detail under Item 3. — Legal Proceedings . Additionally, see —If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.
In addition, between 2023 and 2025 certain of our former employees filed proceedings, including in Virginia federal court, with respect to allegedbreaches of certain stock option grant agreements and related matters. See Item Item 3. — Legal Proceedings for additional information. While most of these proceedings have been resolved, certain of these proceedings remain pending. We disagree with the assertions in each of these proceedings and are defending ourselves and asserting counterclaims, where applicable. There can be no assurance that we will be successful in defending any remaining claims.
Further, a putative securities class action complaint naming Venture Global, our directors and certain of our officers and our underwriters, as well as Venture Global Partners II, LLC, was filed in April 2025 and subsequently amended in September and December 2025. The complaint asserts claims under Sections 11, 12, and 15 of the Securities Act on behalf of a putative class of all persons and entities who purchased or otherwise acquired our Class A common stock pursuant and/or traceable to the registration statement for the IPO and contends that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedlyfalse or misleading and seeks unspecified damages on behalf of the putative class. Further, four putative shareholder derivative action complaints naming Venture Global, our directors, certain of our officers and certain of our underwriters have been filed contending that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedlyfalse or misleading. The complaint asserts breaches of fiduciary duties, gross mismanagement, waste of corporate assets, unjust enrichment, and aiding and abetting, and seeks unspecified damages for such breaches. All four shareholder derivative action complaints have been stayed pending resolution of our motion to dismiss the amended securities class action complaint that we filed on January 28, 2026. See Item 3 . — Legal Proceedings for additional information. The Company believes all of the foregoing claims are without merit and intends to defend itself vigorously.
In addition to these specific disputes, we are and have been involved, and may in the future become involved, in various administrative, regulatory or other legal proceedings, and others have alleged and may in the future allege
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that we are in violation or in default under orders, statutes, rules or regulations relating to the environment, employment law, compliance plans imposed or agreed to by us, or permits issued by various local, state or federal agencies for the construction or operation of our natural gas liquefaction facilities. We have been and may in the future also be subject to claims for personal injury, or property damage, in connection with the construction or operation of our natural gas liquefaction facilities.
Assessment of potential outcomes and the potential damages and other losses we may incur arising out of any current or future disputes or legal proceedings is inherently difficult given, among other things, the complex nature of the facts and law involved. Although we may disagree with any assertions and claims made against us in any such disputes or legal proceedings, we may not be successful in defendingagainst such claims. If legal proceedings are resolved against us or if we make out-of-court settlements, we may be obliged to make substantial payments to other parties. While we maintain liability and other insurance policies, such insurance may be limited and have exclusions that leave us exposed to costs associated with disputes and legal proceedings. Even if we are ultimately successful in the legal proceedings, such proceedings may distract our management team and we may also face harm to our reputation from case-related publicity. Further, any such disputes or legal proceedings could result in substantial costs to us associated with defending such claims and distract management, could have a material adverse effect on our reputation, and could also impact our ability to complete our projects and any natural gas liquefaction and export facility we may decide to develop in the future on their respective anticipated timelines and at their respective anticipated costs.
If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.
We are involved, and may in the future become involved, in disputes and arbitration proceedings with the customers under our SPAs as described in more detail under Item 3. — Legal Proceedings . Certain of such claims have been denied or settled, but a number of such claims remain ongoing and in one instance the customer whose claim was denied in arbitration has filed a petition with the New York Supreme Court seeking to vacate the applicable arbitral award.
We disagree with the assertions and legal claims in each of the ongoing requests for arbitration and the legal proceedings seeking to vacate one such arbitral award, and the Calcasieu Project is vigorously defending the remaining arbitration proceedings and such legal proceedings. While we believe that any damages award in such arbitration proceedings should be subject to the relevant seller aggregate liability cap under the relevant post-COD SPA (other than in in the case of the arbitration award relating to the BP post-COD SPA), there can be no assurance that the Calcasieu Project will be successful in defending such ongoing claims or establishing that any such claim is subject to the applicable liability cap. In addition, although none of the post-COD SPA customers who have commenced the arbitration proceedings described above has sought termination of the underlying post-COD SPA as a remedy in the relevant arbitration, two of those long-term post-COD SPA customers have notified the collateral agent for the Calcasieu Project’s project financing that a potential termination event under their long-term post-COD SPA has occurred or may occur, and that remedies could include termination of, or suspension under, the relevant long-term post-COD SPA.
If the Calcasieu Project is unsuccessful in defendingagainst any of these ongoing claims, the amounts it could be required to pay could be substantial, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects, and contribute to increased volatility in the value of our Class A Common Stock. Further, a termination of, or suspension under, any of the relevant long-term post-COD SPAs that are subject to these claims could, subject to our ability to replace such long-term post-COD SPAs during the applicable grace period, lead to an acceleration of our outstanding debt under the Calcasieu Project and foreclosureagainst all collateral that secures such debt, representing substantially all assets of the Calcasieu Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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If certain customers were to successfullyterminate their post-COD SPAs for the Calcasieu Project, we would need to replace those customers and/or amend the Calcasieu Project's existing post-COD SPAs over a certain period of time that may extend up to 180 days, which could take time and there can be no assurance we would be able to enter into new post-COD SPAs on a timely basis and on comparable or better terms. See —Risks Relating to Our Business—Our customers or we may terminate our SPAs if certain conditions are not met or for other reasons. See also —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.
Risks Relating to Our Projects and Other Assets
We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.
We are in the process of constructing and commissioning the Plaquemines Project, developing and constructing the CP2 Project and developing certain of our other future projects and expansions, including the CP2 Expansion Project and the Plaquemines Expansion Project. While we believe we have sufficient cash and access to substantial commissioning cargo proceeds to fund the completion of the Plaquemines Project and the construction and commissioning of Phase 1 of the CP2 Project based on our current estimate of the Total Project Costs, the development, construction and financing of Phase 2 of the CP2 Project, as well as our other current and future projects and expansions, will require significant additional funding.
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. In addition, as of December 31, 2025, we estimate that the Total Project Cost for the first and second phases of CP2 Project will range from approximately $32.5 billion to $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs, of which $9.9 billion had been paid for as of December 31, 2025. These estimates are based primarily upon our construction cost experiences with the Calcasieu Project and the Plaquemines Project and the pricing included in the CP2 EPC Contracts. They also reflect the current inflationary environment, the potential impact of tariffs in place as of December 31, 2025, as well as the fact that the pipeline for the CP2 Project is expected to be longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. Our actual costs could vary significantly from our preliminary estimates. Further, these cost estimates do not include the cost of the Plaquemines Expansion Project or the CP2 Expansion Project, nor do they reflect the potential impact of any new tariffs that have been announced or implemented after December 31, 2025 or that may be implemented in the future. Our Total Project Cost estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025, but do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Certain of our key components, including our Baker Hughes sourced liquefaction train system modules and power island components, are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects.
Moreover, no substantial construction work has been undertaken on any of our other future projects or expansions to date, and we have not yet entered into a number of material contracts (including EPC contracts) for such other future projects or expansions, and our actual costs could vary significantly from the costs of our other projects depending on the terms we may agree to for those contracts. There is no guarantee that we will be able to enter into the necessary contracts to construct any other future projects or expansions on the same or substantially similar terms as the Calcasieu EPC Contract, the Plaquemines EPC Contracts or the CP2 EPC Contracts. As a
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result, our cost estimates are only an approximation of the actual costs of construction and financing for such projects.
Our actual project costs may be higher, potentially materially, compared to our current estimates as a result of many factors which could result in the need to contribute additional equity into our projects. See further discussion under —Our estimated costs for our projects have been, and continue to be, subject to change due to various factors. For example, our cost estimates might change due to factors such as unexpecteddelays in the construction or commissioning of our projects, the execution of any repair or warranty work and change orders or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for such projects, and/or other construction or supply contracts. Accordingly, we will need to obtain significant additional funding from one or more sources of debt and equity financing before we are able to generate sales and/or revenue for our projects, other than the Calcasieu Project, the Plaquemines Project, and Phase 1 of the CP2 Project.
The amount of project-level equity funding that is required for any of our projects relative to the amount of project-level debt financing may differ between our projects. Generally, we expect to finance approximately 50% to 75% of the anticipated project costs of each of our projects with project-level debt financing (which may include limited recourse debt), and the remaining 25% to 50% with project-level equity (which may consist of equity contributions by us, equity contributed by others, equity financing transactions, mezzanine financing and/or other similar financing alternatives), or cash generated by the relevant project. However, the proportion of project-level debt to equity funding will depend on various factors, including market conditions and the amount of long-term contracted revenues for the relevant project. As a result, there can be no assurance as to the ultimate amount of project-level debt financing that will be available to us for a particular project on acceptable terms, which could have an adverse impact on our ability to finance the relevant project and may require us to raise additional debt, equity or equity-linked financing above relevant project entities, including potentially at the Company level, through additional debt, equity or equity-linked financing. We do not currently have any committed project-level debt or equity financing for Phase 2 of the CP2 Project or any other future projects or expansions. We may consider alternative structures to raise capital for those projects and, as a result, there can be no assurance that the financing structure for Phase 2 of the CP2 Project, or any other future project or expansions we may develop will be similar to those used for the Calcasieu Project, the Plaquemines Project or Phase 1 of the CP2 Project.
Additional capital may not be available in the amounts required, on favorable terms, or at all. In addition, if any adverse findings are discovered at any stage during the course of our development of our projects that would render part of, or all of, any such sites to be unsuitable or we discover flaws that may decrease the value of such sites as collateral for purposes of any financing, then we may not be able to obtain the financing necessary to construct the relevant project on favorable terms, or at all. For example, such adverse findings may include the discovery of environmental conditions on the relevant project site that require investigation, remediation or other changes to the relevant project that make it more difficult for us to obtain the necessary regulatory approvals.
Furthermore, any adverse changes in natural gas demand that affect the competitiveness of LNG or any failure on our part to obtain or comply with necessary permits or approvals may also hinder our ability to obtain necessary additional capital or financing.
Delays in the construction of our projects beyond the estimated development period, issues with the commissioning process leading to additional repair and replacement work, as well as change orders to certain material construction contracts and/or other construction or supply contracts, could increase the cost of completion beyond the amounts that we estimate and beyond the then-available proceeds from sales of commissioning cargos we expect to receive, which could require us to obtain additional sources of financing to fund our operations until our projects are fully completed (which could cause further delays). For example, we experienced unexpecteddelays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, COD for the Calcasieu Project did not occur until April 15, 2025 due to significant work related to commissioning, carryover completions, rectification, and certain other items. Further, while we generated commissioning cargo proceeds at the Calcasieu Project prior to achieving COD and are currently generating commissioning cargo proceeds at the Plaquemines Project, and we plan to sell commissioning cargos at each of our other projects, it is possible those commissioning cargo proceeds will be lower, potentially materially, than we currently anticipate,
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which could also require us to obtain additional sources of capital to fund development, construction and commissioning of our projects.
Our future liquidity may also be affected by the timing and availability of financing in relation to the incurrence of construction costs for our projects and other outflows and by the timing of receipt of cash flow under the SPAs in relation to the incurrence of various project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements.
Our ability to obtain financing that may be needed to provide additional funding will depend, in part, on factors beyond our control and there can be no assurances that funding will be available to us on acceptable commercial terms or at all. For example, capital providers or their applicable regulators may elect to cease funding LNG projects or certain related businesses. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our business plan and the viability of the relevant project. The failure to obtain any necessary additional funding could cause any or all of our projects to be delayed or not be completed. Any delays in construction could prevent us from commencing operations when we anticipate and could prevent us from realizing anticipated cash flows, all of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We may not construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, and we may not pursue some or any of the bolt-on expansion opportunities we have identified at our current projects, which could limit our growth prospects.
We may not construct some of our proposed LNG facilities or pipelines, and we may not pursue some or any of the bolt-on expansion opportunities we have identified at our current projects, in each case whether due to lack of commercial interest, inability to obtain financing, inability to obtain adequate supply of materials and equipment to complete construction of our projects, inability to obtain necessary regulatory approvals (including as a result of political factors, environmental concerns or public opposition) or otherwise. For example, we previously decided to withdraw the Delta Project from the FERC pre-filing process and replace the Delta Project with the proposed Plaquemines Expansion Project. Our ability to develop additional liquefaction facilities or to pursue bolt-on expansion opportunities at our projects will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world regulatory approvals, and other factors. If we are unable or unwilling to construct and operate additional LNG facilities or bolt-on expansion opportunities at our current projects, our prospects for growth will be limited.
O ur natural gas liquefaction and export projects face, and our future projects or expansions may face, significant operational risks.
As more fully discussed in these —Risk Factors , our existing and future projects, and expansions thereof, involve operational risks, including the following:
• explosions, pollution, releases of toxic substances;
• the facilities performing below expected levels of efficiency;
• breakdown or failures of equipment;
• unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend in part on supplies of and prices for alternative energy sources and the discovery of new sources of natural resources;
• operational errors by vessel or tug operators;
• operational errors by us or any contracted facility operator;
• labor disputes; and
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• weather-related interruptions of operations, natural disasters, fires, floods, accidents or other catastrophes.
If any of such operational risks materializes, it could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We have multiple procurement and construction contracts. Failure by one contractor to perform under its applicable material procurement and/or construction contract could lead to failure to perform or delay in performance by others under their construction contracts.
Our strategy for each project involves us entering into and administering a number of procurement and construction contracts, which differs from certain other LNG projects of this scale developed in the United States.
Failure of any of the counterparties to these procurement and/or construction contracts to complete its contractual obligations on a timely basis could result in material delays in the ability of our projects to achieve commercial operation. In addition, any such failure by any of the foregoing counterparties could affect the schedule of other construction contractors and/or require change orders to multiple material construction contracts. Although the scope of each such contractor is defined in the applicable material contract to which it is a party, in the event of delays or other procurement or construction issues, each such contractor may seek to shift responsibility for delays or other issues to other contractors, resulting in increased costs or delays.
We are dependent on our contractors for the successful completion of our projects and any bolt-on expansion opportunities at our projects that we may pursue, and any failure by our contractors to perform their contractual obligations could have a material adverse impact on our projects.
There is limited recent industry experience in the United States regarding the construction or operation of mid-scale natural gas liquefaction and export facilities. Timely and cost-effective completion of our projects or any bolt-on expansion opportunities at our projects in compliance with agreed upon specifications is highly dependent upon the performance of our contractors pursuant to their agreements with us. Moreover, our construction strategy involves multiple construction contracts, which differs from certain other LNG projects of this scale developed in the United States. Failure by one contractor to perform under its applicable material construction contract could lead to failure to perform or delay in performance by others under their construction contracts.
Successful construction and operation of our projects, or any bolt-on expansions at our projects, will depend on the adequacy and timeliness of performance of our contractors. The failure of our contractors to perform as expected could have a material adverse impact on our ability to complete our projects, or any bolt-on expansions at our projects, on our anticipated schedule and budget, or at all. Further, if the completion and the commercial operation date of the Plaquemines Project or the CP2 Project are delayed beyond an agreed date certain for each project, an event of default under the Plaquemines Credit Facilities, the VGPL Senior Secured Notes, the CP2 Credit Facilities or the CP2 EBL Facility, may occur. See —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.
Further, our ability to complete our projects, or any bolt-on expansions at our projects, and commence operations at each of our projects, or any bolt-on expansions at our projects, depends on completion of construction of our projects, or any bolt-on expansions at our projects, in accordance with our design and quality standards. Faulty construction that does not conform to those standards could have a material impact on our ability to complete our projects, or any bolt-on expansions at our projects, on our anticipated schedule, and could also have material adverse effects on the operation of the facilities (for example, improper equipment installation may lead to a shortened life of our equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility).
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Timely and cost-effective completion of the projects, or any bolt-on expansions at our projects, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance by the construction contractors of their obligations under the material construction contracts. The ability of our current or intended contractors to complete our projects in accordance with our design and quality standards and on our anticipated schedule is dependent on a number of factors, including such construction contractor’s ability to, as applicable:
• maintain its own financial condition, including adequate working capital, and its ability to pay debt service and other liabilities;
• accurately estimate certain costs, including material, construction and fabrication costs, from third parties such as suppliers and subcontractors;
• respond to difficulties such as equipment failure, increased costs, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
• design, engineer and build the facilities constituting the projects to operate in accordance with specifications and on schedule;
• engage and retain third-party subcontractors and procure equipment and supplies;
• attract, develop and retain skilled personnel, including engineers, and address any labor issues that may arise;
• respond to market conditions in the construction industry, including recent shortages of personnel and recent increases in operating costs;
• address any start-up and operational issues that may arise in connection with the commencement of commercial operations;
• post and maintain required construction bonds or other performance assurance and comply with the terms thereof; and
• manage the construction process generally, including coordinating with other contractors, third-party contractors and regulatory agencies.
Although agreements with our contractors may provide for liquidateddamages if the relevant contractor fails to perform its obligations under the applicable agreement, such failure may delay or permanently impair the operations of our projects, or any bolt-on expansions at our projects. Moreover, any liquidateddamages that we may be entitled to receive may be subject to certain liability caps, and may not be sufficient to cover the damages that we suffer, or that we may be required to pay to our customers or our lenders as a result of any such delay or impairment. Furthermore, we may have disagreements with our current or intended contractors about different elements of the construction process or our construction contracts, which could lead to the assertion of rights and remedies under the related contracts resulting in increases to the cost of the project, or any bolt-on expansions at our projects, or such contractor’s unwillingness to perform further work on our projects, or any bolt-on expansions at our projects, or to pay liquidateddamages. For example, VGCP had disagreements regarding certain disputed costs and bonuses with Kiewit, our EPC contractor for the Calcasieu Project that were submitted to arbitration. Such disputes were fully resolved in 2024 and resulted in the payment by us of approximately $320 million, in the aggregate, to Kiewit.
In addition, if our current or intended contractors, or any of their parents or affiliates that provide performance guarantees, letters of credit or similar credit support, consummate any significant acquisitions, dispositions, restructurings or other strategic transactions, or become subject to bankruptcy or similar proceedings, our ability to complete our projects, or any bolt-on expansions at our projects, in accordance with our design and quality standards and on our anticipated schedule, and our ability to recover under any such performance guarantees, letters of credit or similar credit support, may be adversely affected.
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For example, in 2024 Zachry Industrial, Inc., one of the joint owners of KZJV, LLC, the EPC contractor for the Plaquemines Project, filed for bankruptcy protection under Chapter 11 of the U.S. bankruptcy code. While Zachry Industrial, Inc. successfully emerged from Chapter 11 proceeding in 2025 and we were able to successfully mitigate most of the bankruptcy’s impacts to the construction of the Plaquemines Project, there can be no assurance that any future bankruptcies of any of our contractors will not have a material adverse impact on any of our ongoing projects. Any such future contractor bankruptcies could result in material delays or termination of any of our projects and could have a material adverse impact on our ability to complete such projects on our anticipated schedule and budget, or at all.
If any contractor or supplier is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor or supplier. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We have not entered into all of the definitive agreements for our future projects and expansions, and there can be no assurance that we will be able to do so on a timely basis or on terms that are acceptable to us.
To date, we have not yet entered into all of the necessary definitive agreements with the key suppliers and contractors necessary for development and construction of all our future projects and expansions. While we have entered into the Baker Hughes Master Agreement and we have sufficient capacity for our currently planned future projects and expansion, we have not yet entered into EPC contracts or all other material supply agreements for all of our other future projects or expansions. We may not be able to successfully negotiate the outstanding necessary definitive contracts for our other future projects or expansions, on a timely basis or on terms or at prices that are acceptable to us. Our inability to negotiate and execute definitive agreements with such contractors on a timely basis or on terms acceptable to us could have a material adverse impact on our ability to complete our future projects and expansions, on our anticipated schedule and budget, or at all. Moreover, the development and construction of our future projects or any expansions thereof, may be delayed or they may not be built at all, and the construction cost of such future projects or expansions, may be greater than our current estimates.
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.
Certain of our contractual arrangements relating to development and construction of our projects include termination rights that, if exercised, could have a material adverse impact on our projects.
Certain of our contractual arrangements relating to the development and construction of one or more of our projects include termination rights or changes to the applicable pricing, or will automatically expire, if certain conditions are not met by specified deadlines.
For example, under the Baker Hughes Master Agreement, if we fail to enter into purchase orders for the liquefaction systems and the power plant for our future development projects by certain mutually agreed dates or to begin making scheduled payments, then Baker Hughes’ obligations to supply such equipment will expire unless Baker Hughes agrees to extend those dates. In addition, Baker Hughes has agreed to reserve manufacturing capacity for purposes of fabricating equipment to be supplied under the agreement. While we have executed the applicable purchase orders for the Plaquemines Project and the CP2 Project, we have not yet executed any such purchase orders for any of our other future projects or expansions. If we do not execute applicable purchase orders by the applicable dates in the agreement, Baker Hughes may utilize the relevant manufacturing capacity for other purposes and delivery of equipment by Baker Hughes under the agreement could be delayed. Based on our anticipated project schedule, we currently expect that we will be in a position to deliver the purchase orders for our currently planned projects and bolt-on expansions to Baker Hughes by the applicable deadlines in the Baker Hughes Master Agreement, as such deadlines may be amended from time to time. However, if a project is delayed for any reason (including the reasons described elsewhere in this —Risk Factors section), Baker Hughes’ obligations with respect to the remaining equipment to be delivered would expire unless we either (i) deliver the applicable purchase order
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and commence making payments on the agreed schedule, or (ii) agree with Baker Hughes on an extension of the applicable deadline under the agreement. There can be no assurance that we would be able to negotiate any such extension on terms that are acceptable to us or at all, or that we will have the financial resources to make the scheduled payments with respect to a purchase order prior to commencement of construction and financing of the relevant project.
The termination of any of the definitive agreements we have entered into with contractors, or any change to the pricing under those agreements, could have a material impact on our ability to complete the Plaquemines Project, the CP2 Project, or any other future projects or expansions, on our anticipated schedule or budget, or at all.
Our estimated costs for our projects have been, and continue to be, subject to change due to various factors.
Our cost estimates for LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities have been, and continue to be, subject to change due to many factors outside of our control. Such factors include, among other things, (i) inflationary factors, (ii) changes in commodity prices (particularly nickel and steel), (iii) escalating labor costs, (iv) supply chain availability, including the availability of critical components and increased costs to locate and procure alternatives, (v) labor disputes, (vi) tariffs, (vii) unexpecteddelays in construction or commissioning, (viii) unexpected repair, replacement, rectification and warranty work, and (ix) resolving contract closeout and true-up matters. Such factors have in the past resulted in, and may in the future result in, among other things, delays in construction or commissioning, repair or warranty work, cost overruns, and/or change orders under or amendments to existing or future construction contracts. Further, we may decide or be forced to enter into amendments to construction and/or supply contracts or submit change orders to the applicable contractor that could result in longer construction periods, higher costs, or both. We may also decide or be forced to expend additional funds in order to maintain construction schedules, complete construction and commissioning, or comply with existing or future environmental or other regulations. Additionally, our estimated costs for our projects do not include the potential costs of any new tariffs that have been implemented since December 31, 2025 or that may be implemented in the future or estimated costs for any potential bolt-on expansion opportunities that we may pursue in the future, including as a consequence of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government and the federal government’s decision to impose incremental baseline tariffs as a result. As a result, costs to achieve completion of LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities may be higher, potentially materially, than our cost estimates. In the event we experience any such increases in estimated costs, delays or both, the amount of funding needed to complete an LNG facility, a phase thereof, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities, could exceed our available funds and result in our failure to complete such projects or assets and thereby negatively impact our business and limit our growth prospects. See — We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs and —Risks Relating to Regulation and Litigation—If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.
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 December 31, 2025. This estimate is based in part on the target cost determined pursuant to the Plaquemines EPC Contracts and reflects increases related to, among other things, inflationary factors and efforts to maintain the project schedule while also reserving additional contingency funds (without giving effect to any commissioning cargo proceeds that may be utilized for project costs). Since FID of Phase 2 of the Plaquemines Project through the date of this Form 10-K, VGLNG has made several incremental equity contributions to VGPL in an aggregate amount equal to approximately $3.4 billion to address such increases in estimated Total Project Costs, and we may be required to make additional incremental equity contributions to the extent Total Project Costs exceed the low-end of the range of estimated Total Project Costs above and that such costs exceed the available project-level debt, equity financing and net proceeds from the sale of commissioning cargos. Pursuant to the Plaquemines Credit Facilities, if such contributions have been utilized to pay project costs
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for the Plaquemines Project, they are reimbursable by VGPL to VGLNG at our election upon satisfaction of certain conditions under the Plaquemines Construction Term Loan. The costs to achieve completion of the Plaquemines Project may be subject to further increases, which could be material, as a result of many factors outside of our control as described above. As a result, we may need to make additional equity contributions or raise additional project-level equity financing or debt financing in the future to fund any such increase in estimated Total Project Costs that exceeds our current contingency, and any such additional contributions or funding could be significant. Further, such cost estimates do not reflect the cost of any potential incremental bolt-on expansion capacity that we may elect to implement in the future.
We currently estimate that the Total Project Costs for Phases 1 and 2 of the CP2 Project will range from approximately $32.5 billion to $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. Approximately $9.9 billion of the Total Project Cost for Phases 1 and 2 of the CP2 Project has been paid as of December 31, 2025. This estimate is based primarily upon our construction cost experiences with the Calcasieu Project and the Plaquemines Project, the pricing included in the CP2 EPC Contracts, and reflect the current inflationary environment as well as the fact that the pipeline for the CP2 Project is longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. Our actual costs could vary significantly from our preliminary estimates depending on the terms we may agree to for those contracts. As a result, our cost estimates are only an approximation of the actual costs of construction and financing for the CP2 Project. Such cost estimates also do not reflect the cost of any potential incremental bolt-on expansion capacity that we may elect to implement in the future.
Further, the cost reimbursement arrangements under our existing EPC contracts provide that the EPC contractor will be reimbursed for all reimbursable costs incurred in connection with the relevant work, and while the EPC contractor’s profit margin will decrease as the amount of cost overrun increases, we are obligated to reimburse the EPC contractor for all reimbursable costs incurred under the EPC contract. However, EPC contracts that we enter into in the future may not include similar cost protections, which could lead to greater cost overruns for our other projects. Any increase in the construction costs for any of our projects could have an adverse impact on our business plan and the viability of the relevant project, and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our cost estimates with respect to any LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, regasification facilities and other natural gas liquefaction and export facilities (including any expansion of an existing facility) we may decide to develop in the future would be subject to similar uncertainties and potential changes. For example, our cost estimates may continue to increase as we negotiate and finalize agreements with contractors for any such project.
In addition, our cost estimates do not reflect the potential impact of any changes to tariffs that have been announced or implemented since December 31, 2025 or that may be implemented in the future. Our project budget estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025, but do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Certain of our products are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects. See Item 7 .—Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources—Funding Requirements . Any increases in the construction costs for any of our projects could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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Delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our current schedule for the completion of our projects may turn out not to be achievable. For example, our ability to complete our projects on the anticipated schedule is dependent upon our timely receipt and maintenance of required regulatory approvals and permits and upon various activities being completed by our contractors. Any significant construction or commissioning delay, as a result of regulatory issues or otherwise, could increase the total cost of the relevant projects and would cause a delay in the completion of the construction of our projects, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
In addition, delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our contracts. For example, we experienced unexpecteddelays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, COD for the Calcasieu Project occurred on April 15, 2025, which is later than originally forecasted, after significant work related to commissioning, carryover completions, rectification, and certain other items was completed. Although we are currently generating revenue from sales of LNG commissioning cargos from the Plaquemines Project prior to commencing commercial operations, we will not generate any revenues or cash flows under our post-COD SPAs (including the intercompany excess capacity SPAs) until we have achieved COD at the project. Additionally, a failure to achieve the project completion date for a project by a date certain may result in an event of default under the related project financing, and, if such debt is accelerated, an event of default under our other financing agreements for that project or otherwise. Any such event of default would entitle the applicable debtholders to exercise certain remedies, including to accelerate the debt obligations under their respective debt instruments and to forecloseagainst all collateral that secures such debt, representing substantially all assets of the relevant project, which could seriouslyharm our business and lead to a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. See —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.
Any delay in a project’s ability to produce and load LNG for sale or delay in the completion of our projects could cause a delay in the receipt of proceeds projected from sales of LNG commissioning cargos, sales by VG Commodities, and/or from Contracted SPAs, or lead to a loss of one or more customers in the event of significant delays. For example, each of our post-COD SPAs provides that the counterparty may terminate that SPA in the event that such project has not achieved COD by the relevant deadlines, and such counterparties could also bring claims for contractual damages. In addition, each of our Firm-start SPAs requires that we pay certain cover damages if VG Commodities fails to make available LNG in the quantities set forth in the respective Firm-start SPA. We cannot assure you that we will have sufficient LNG capacity at our projects that is not otherwise committed to meet our obligations under our Firm-start SPAs if the relevant deadlines occur prior to COD of the relevant project. See —Risks Relating to Regulation and Litigation—We are involved, and may in the future become involved, in disputes and legal proceedings and —Risks Relating to Regulation and Litigation—If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.
We are dependent on third party vendors and service providers to provide certain services and equipment to our projects.
We rely on third party vendors and service providers to provide certain services, supplies, products and equipment to our projects. We have entered into agreements with these third parties in connection with such
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services, supplies, products and equipment. However, the ability of our third party vendors and service providers to perform successfully under their agreements is dependent on a number of factors, including their ability to:
• maintain their own financial condition, including adequate working capital, and their ability to pay debt service and other liabilities;
• accurately estimate certain costs;
• meet quality or performance standards for third party equipment;
• procure equipment and supplies;
• execute requisite work and services efficiently; and
• attract, develop and retain skilled personnel.
If any third party vendor or service provider is unable or unwilling to perform according to the terms of its respective agreement for any reason or terminates its agreement, we may need to engage a substitute vendor or service provider. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Various economic and political factors, including opposition by environmental or other public interest groups, could negatively affect the timing or overall development, construction and operation of our projects, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to commence liquefaction operations and produce LNG at our projects (other than the Calcasieu Project which commenced production of LNG in January 2022 and commercial operations in April 2025, and the Plaquemines Project, which commenced production of LNG in December 2024 and remains in the commissioning process) or any other natural gas liquefaction and export facility (or expansion of an existing facility) we may decide to develop in the future is dependent on the construction of the relevant facility (or expansion thereof), which will require the expenditure of significant amounts of capital that may exceed our estimates. The development and construction of our projects, as well as their commissioning prior to commercial operation, and any other natural gas liquefaction and export facilities (or expansion of an existing facility) that we may decide to develop in the future takes a number of years and may be delayed by factors such as:
• our ability to obtain or maintain necessary permits, licenses and approvals from regulatory agencies and third parties that are required to construct or operate the relevant project;
• our ability to enter into final ground leases for the relevant project site;
• the identification of any adverse issues with respect to the relevant project site;
• our ability to obtain right-of-way permits, servitudes or other similar property rights necessary to construct the pipelines required to interconnect the relevant project site with natural gas suppliers;
• our ability to administer our existing EPC Contracts and to successfully negotiate definitive agreements with EPC contractors for our future projects and expansions we develop, as well as with other advisors, contractors and consultants necessary for the development and construction of the relevant project in a timely manner for each of our projects;
• our ability to maintain or secure definitive Contracted SPAs for an adequate portion of the expected nameplate capacity of the relevant project, including for our future projects, and phases or expansions thereof, that are needed to support an FID for each such project, phase or expansion;
• our ability to secure necessary additional capital or financing on satisfactory terms, or at all, to develop our future projects and expansions thereof;
• the discovery of environmental conditions on the relevant project site that require investigation, remediation or other changes to the relevant project;
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• failure by our contractors to fulfill their obligations under their contracts relating to the development and construction of the relevant project, or disagreements with them over their contractual obligations;
• as construction progresses, we may decide or be forced to submit change orders to our contractors that could result in longer construction periods and higher than anticipated construction expenses;
• force majeure events, natural or man-made disasters, terrorist attacks or sabotage;
• shortages of materials or delays in the delivery of materials;
• weather conditions and impacts from potential climate change, hurricanes, severe weather events and other catastrophes, such as explosions, fires, floods and accidents;
• local and general economic and infrastructure conditions;
• political unrest or local community resistance or resistance by environmental groups and other advocates or impacts to indigenous peoples or impact by indigenous people to the development of the relevant project due to health, safety, environmental, or security or other concerns;
• our ability to attract sufficient skilled and unskilled labor, the existence of any labor disputes, our ability to maintain good relationships with our contractors in order to construct the relevant project within the expected parameters and the ability of those contractors to perform their obligations;
• economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
• decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects; and
• other risks inherent to the construction, expansion and operation of LNG facilities and other natural gas liquefaction and export facilities.
Many of these factors are outside of our control.
More generally, the regulatory approval process for many LNG and natural gas infrastructure projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to natural gas exploration and production, pipeline activities and associated environmental impacts, and increased opposition to the natural gas industry and related infrastructure. We have not yet obtained the requisite regulatory authorizations for all of our planned projects. For instance, additional authorizations are still required from FERC for the CP2 Project as we proceed with its construction and commissioning consistent with the terms and conditions in FERC’s authorization. Furthermore, while we have proposed to increase the authorized production capacity of both the Plaquemines and CP2 projects, neither FERC nor DOE has yet authorized those increases. Similarly, we only recently applied for authorizations for the Plaquemines Expansion Project. The requisite regulatory authorizations for all of these projects potentially may be delayed, conditioned, or even denied.
Furthermore, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed, reversed, and vacated. Increased opposition and regulatory challenges may harm our ability to obtain and maintain necessary regulatory approvals. For example, on November 27, 2024, in response to project opponents challenging FERC’s authorization for the CP2 Project, FERC issued an order on rehearing that generally rejected the argumentsopposing the CP2 Project, but partially “set aside” its prior analysis to initiate a supplemental environmental review of certain discrete potential impacts of the project. FERC subsequently affirmed the authorization in subsequent orders in 2025 but the supplemental environmental review delayed on-site construction. The opponents of the CP2 Project have filed petitions with the U.S. Court of Appeals for the D.C. Circuit challenging FERC’s orders authorizing the CP2 Project. In addition, in August 2025, environmental groups filed a lawsuit in the U.S. Court of Appeals for the Fifth Circuit challenging permits issued by the Louisiana Department of Environmental Quality for the CP2 Project. Furthermore, in February 2026, environmental groups filed another appeal in the Court of Appeals for the D.C. Circuit challenging DOE’s order authorizing exports to Non-FTA Nations by the CP2 Project. There can be no assurances as to the outcome of such pending proceedings.
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There can be no assurance that our existing or future regulatory approvals will not be subject to other legal challenges, or that such approvals will not be re-examined vacated, withdrawn, overturned, altered or otherwise modified in a manner adverse to the development, construction or operation of one or more of our projects or to our business more generally. If we are required to modify our activities as a result of the pending judicial appeals or other changes to our existing regulatory approvals, the impact could increase our project costs, delay our project timelines, affect our ability to complete our planned projects, or result in claims from third parties if we are unable to meet our commitments under our pre-existing commercial agreements, all of which could have a material adverse effect on our business. Any delay in completion of our projects that prevents us from producing and loading LNG when anticipated would also cause a delay in the receipt of revenues therefrom, potentially require us to pay damages to selected customers with whom we have entered into definitive SPAs, or, in the event of significant delays beyond certain time periods, permit customers to terminate their contractual obligations to us.
In addition, the successful completion of our projects is subject to the risk of cost overruns, schedule delays, weather disruptions, labor disputes and other factors, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our business could be materially and adversely affected if we do not secure the right or if we lose the right to situate certain lateral pipelines, longer-haul pipelines or any other pipeline infrastructure for any of our projects on property owned by third parties, or if we do not complete the construction of those pipelines in a timely fashion.
We expect to obtain access to the natural gas required for the operation and commissioning process for our projects through certain lateral and longer-haul pipeline connections that we plan to construct as part of those projects, each of which will connect the relevant LNG facility to one or more third-party pipelines. While the lateral pipelines for both the Calcasieu Project and the Plaquemines Project are complete, much of this contemplated pipeline infrastructure has not been completed. As we are expanding our development footprint with the our future projects and expansions, these projects’ production capacities will require natural gas volumes that necessitate the construction of longer interstate and intrastate pipelines that provide incremental access and delivery capability from the Permian, Haynesville, Western Haynesville, Eagle Ford, mid-continent shale, and other formations. We plan to construct significant 48-inch diameter, compressed pipeline infrastructure, both independently and in partnership with certain qualified third parties, sufficient to source the required natural gas for these projects from primarily the Permian, Haynesville and Western Haynesville shale plays. Timely completion of such pipelines will be subject to numerous risks, such as interface risks with our third-party partners, weather delays, accidents, inability to obtain required rights-of-way and servitudes, and regulatory approvals. Opposition to regulatory approvals for the pipeline projects could delay or prevent their completion, which could have an adverse impact on our business and operations
We do not expect to own or lease the vast majority of the tracts of land on which we expect to construct the pipeline infrastructure that will connect our projects to third-party pipelines and other sources of natural gas. As a result, we need to secure servitudes, rights-of-way and similar rights necessary for the construction of that pipeline infrastructure. Although we have obtained permanent servitudes in respect of all of the land on the TransCameron Pipeline route for the Calcasieu Project, the Gator Express Pipeline route for the Plaquemines Project and substantially all the land for the CP Express Pipeline for the CP2 Project, certain tracts in respect of which we have obtained such rights are currently burdened by mortgages that would be superior to our rights. While the servitudes we obtain generally contain clauses that require the relevant landowners to use commercially reasonable efforts to provide us with subordination, non-disturbance and attornment agreements, or the SNDAs, if we request them, there can be no assurance that any such SNDAs, or any other measures we take, will result in us having adequate real property rights with respect to these tracts. Moreover, with respect to the other pipelines that we plan to develop, we have not yet obtained all of the rights necessary to construct the pipeline infrastructure expected to connect those projects to third-party pipelines and other sources of natural gas, and there can be no assurance that we will be able to obtain the necessary property rights on terms satisfactory to us, or at all.
As a result of these factors, our pipeline infrastructure for our future projects and expansions is subject to the possibility of increased costs to obtain necessary land use rights. If we were unable to obtain those rights or if we
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were to lose any such rights with respect to a project, or if we were required to relocate any of our pipeline infrastructure, our business could be materially and adversely affected.
There is no assurance that our projects will receive the local government and community support required for construction.
The development and construction of our projects requires support and approval from local governments with jurisdiction over the project sites and support from the communities in which they are located. While we believe we have requisite local government and community support in Cameron Parish and Plaquemines Parish, where our projects our located, there is no assurance that we can maintain such support or that we will receive such support for other projects, including any expansions thereof, we may develop in the future. Any failure to obtain or maintain the requisite local government and community support for our projects, or for any other natural gas liquefaction and export facility we may decide to develop in the future, could have a material adverse effect on our ability to develop and construct that project on our anticipated schedule, or at all.
Our real property rights in the sites for our projects or any other natural gas liquefaction and export facilities that we may decide to develop in the future may be adversely affected by the rights of others that are superior to those of the grantors of our real property rights.
The Calcasieu Project, the Plaquemines Project, the CP2 Project, and our other future projects and expansions thereof, and our pipeline development projects that we may decide to develop in the future are likely to be located on land subject to long-term servitudes, leases, rights of way and similar agreements with landowners. The ownership interests in the land subject to these servitudes, leases, rights-of-way and similar agreements may be subject to mortgages securing loans or other liens (such as tax liens) and other servitudes, lease rights and rights-of-way of third parties that were created prior to our servitudes, leases and rights-of-way. As a result, certain of our rights under these servitudes, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties.
We perform title searches, obtain title insurance and enter into non-disturbance agreements to protect ourselves against these risks. Such measures may, however, be inadequate to protect our operating projects against all risk of loss or impairment of our rights to use the land on which our existing and future projects are located.
Any such loss or curtailment of our rights to use the land on which our projects or any other future project is located, and any increase in rent due on such lands, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects and could also adversely affect our ability to secure necessary additional capital for the relevant project.
The natural gas liquefaction system and mid-scale design we utilize at our projects are the first of such sized modules developed by us and Baker Hughes, and there can be no assurance that these modules, or our projects, will achieve the level of performance or other benefits that we anticipate over the long term.
We are constructing our projects using a natural gas liquefaction system provided by Baker Hughes that is deployed in a unique mid-scale, factory-built configuration that we developed. While Baker Hughes has developed liquefaction systems utilizing both larger and smaller modules before, the specific liquefaction modules that we are using are the first of such sized modules produced by Baker Hughes, and accordingly the configuration, production, transportation, installation and commissioning of such sized modules has not yet been tested in LNG projects, except for the Calcasieu Project and the Plaquemines Project. As a result, there may be issues with respect to this design that have not yet been identified, notwithstanding the current production of LNG at the Calcasieu Project and the Plaquemines Project, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. While Baker Hughes has an obligation to ensure the liquefaction systems meet minimum performance guarantees, there can be no assurance that the liquefaction system is able to satisfy the minimum performance guarantees or maintain such performance guarantees throughout the operating life of a facility.
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We have the right under the Baker Hughes Master Agreement to require Baker Hughes to enter into a long-term service agreement on specified terms with respect to long term maintenance, repair, and servicing of the liquefaction, power, and booster compressor equipment it supplies. While we have entered into a long-term service agreement with Baker Hughes for the Calcasieu Project and the Plaquemines Project, under which Baker Hughes guarantees the minimum performance and operating availability of certain liquefaction and power systems it supplies, we have not yet negotiated the final terms for any such long-term service agreement for any other projects. Notwithstanding our rights under the Baker Hughes Master Agreement, there can be no assurance that we will enter into the long-term service agreement with Baker Hughes on the same terms as we currently anticipate. If we encounter issues with the new technology, including, for example, higher operating or maintenance expenses, lower performance standards or more downtime than we currently anticipate, our projects may not be able to produce the quantity or volume of LNG we anticipate and our projects may be delayed and the financial viability of our projects may be adversely impacted. Any of these factors could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
The phased commissioning start-up of our projects will subject us to additional risks.
The unique configuration of our LNG projects necessitates a phased commissioning start-up process for each of our projects (and phases thereof) that will generally result in a longer commissioning process. The length of any commissioning process depends on a number of factors related to equipment performance and the ability to establish reliable and safe operations for that equipment and the facility as a whole. For example, once we have sufficient power to operate the first pre-treatment unit, and the first LNG storage tank and first gas pre-treatment unit have been installed for a particular project, we generally begin the commissioning start-up of the relevant equipment on a phased basis. This sequential commissioning of the liquefaction trains, power island system, pre-treatment system, and other equipment for a project is subject to several risks, some of which may be unknown to us.
For example, the simultaneous construction of a particular LNG facility and production of LNG at that facility could subject us and our third-party contractors to additional safety hazards, as well as additional costs related to the management of those safety hazards during the phased commissioning start-up of a facility. To successfully implement our phased commissioning start-up, our EPC contractors will be required to develop and implement a safe work plan. Furthermore, we will require additional regulatory approvals from FERC for all of our construction and commissioning activities, including approval of our EPC contractor’s safe work plan, in order to implement our phased commissioning start-up at a facility before construction has been completed. Any delays in implementing any of the measures required for the phased start-up of our facilities or in obtaining the necessary regulatory approvals, and any additional costs associated with the phased start-up of our facilities, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We are and will be relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our projects, and these estimates may prove to be inaccurate.
We are and will be relying on third parties, principally the construction contractors, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of our projects. If any of our liquefaction facilities for our projects, when completed, fails to have the capacity ratings and performance capabilities that we intend, the estimates set forth in this Form 10-K may not be accurate. Failure of any of our liquefaction facilities for our projects to achieve our intended capacity ratings and performance capabilities could prevent us from satisfying the performance tests required in order to achieve COD start dates under our post-COD SPAs and cause the quantity of LNG we produce to fall short of our contractual delivery obligations to customers and could have a material adverse effect on our business, contracts, operating results, financial condition, cash flow, liquidity, financing requirements and prospects. Further, we will not generate any revenues or cash flows under our post-COD SPAs or from sales to third parties of excess capacity covered by the intercompany excess capacity SPAs, in each case until we have achieved COD for the relevant project.
Additionally, satisfying required performance tests is a condition precedent for project completion under our project financing, and a failure to achieve the project completion date for a project by a date certain may result in an
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event of default under those project financing documents. If such debt is accelerated, it may also result in an event of default under our other financing agreements for that project or otherwise. Further, under certain financing agreements we may be required to (i) maintain in effect all material project agreements, including the relevant EPC contract, for a particular project and (ii) comply in all material respects with their payment and other material obligations under the material project agreements for such project, and any breach of such requirements may, after any applicable cure periods, result in an event of default under our other financing agreements for that project or otherwise. Any such event of default would entitle the applicable debtholders to exercise certain remedies, including to accelerate the debt obligations under their respective debt instruments. See —Delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Construction and operations of natural gas pipelines and lateral pipeline connections for our projects are subject to a number of regulatory approvals, development risks, operational hazards and other risks, which could cause cost overruns and delays and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We have completed the construction of two of our natural gas pipeline projects, the TransCameron Pipeline and the Gator Express Pipeline. Construction and operations of our future, planned natural gas pipelines and pipeline connections for our projects, including the CP Express natural gas pipeline, which is permitted and under construction, and the pipelines required for our other future projects and expansions, which are not yet permitted, are subject to the risks of delay or cost overruns inherent in any construction project resulting from numerous factors, including, but not limited to, the following:
• failure to obtain and maintain relevant approvals and permits from governmental and regulatory agencies;
• difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;
• difficulties in engaging qualified contractors necessary for the construction of natural gas pipelines and lateral pipeline connections for any of our projects;
• shortages of equipment, material or skilled labor;
• natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents and terrorism;
• unscheduleddelays in the delivery of ordered materials;
• EPC productivity factor realization, work stoppages and labor disputes;
• difficulties or delays in obtaining, or failure to obtain, sufficient real property interests on which to construct and locate the pipelines and associated facilities;
• unexpected or unanticipated need for additional improvements;
• unexpected additional material quantities and labor hours; and
• adverse general economic conditions.
Delays beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts that are currently estimated, which could require us to obtain additional sources of financing to fund the activities. Any delay in completion of the pipelines may also cause a delay in commencement of commercial operations of our projects even if the projects are substantially complete for commercial operations. As a result, any significant construction delay in construction of the natural gas pipelines and lateral pipeline connections, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
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If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport natural gas or if there are any reductions in the capacity of, or the allocations to, interconnecting third-party pipelines, this could cause a reduction of volumes transported to our facilities and could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
We depend and will continue to depend upon third-party pipelines and other facilities interconnecting with our projects to provide material gas delivery options to our liquefaction and export facilities. We have entered into multiple agreements with various pipelines for the transport of natural gas to the Calcasieu Project and the Plaquemines Project. The transport of natural gas to the Calcasieu Project and the Plaquemines Project has been secured through a portfolio of approximately 10- to 20-year transportation arrangements. The CP2 Project has also entered into agreements for firm transportation capacity with third parties and CP Express. We are also in the process of contracting for, or developing, the additional required transportation capacity in support of our other projects. We do not have any control over the operation, development, expansion, or maintenance of these third-party pipelines or certain other third-party pipeline facilities that may be interconnected with our projects in the future.
The design, construction and operation of natural gas pipelines are highly regulated activities. Approvals of FERC under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an interstate natural gas pipeline, and those approvals may be subject to judicial appeals. Intrastate pipelines not regulated by FERC under the NGA nevertheless require other governmental approvals. Neither we nor our SPA customers have any control over the ability of third-party pipelines to obtain, maintain or comply with any such regulatory approvals and permits.
Additionally, the capacity on interconnecting pipelines may not be sufficient to accommodate additional liquefaction trains we may construct if we undertake an expansion of our project facilities, including the potential bolt-on expansion for the Plaquemines Project. Further, if we need to replace one or more of our interconnection agreements or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all.
If we are unable to secure any necessary pipeline interconnections, or if any third-party pipelines or pipeline connections that we currently depend upon were otherwise to become unavailable for current or future volumes of natural gas due to a failure to obtain or maintain regulatory approvals or permits, repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas from producing regions to our projects could be restricted, which could have a material adverse effect on our business and operations, and on our ability to perform under the SPAs.
Delays in deliveries of newbuild LNG tankers, and increases in price or building costs, could harm our operating results.
The delivery of newbuild LNG tankers to us could be delayed, not completed or cancelled, which could delay or eliminate our ability to optimize contracts with spot and term customers seeking delivered LNG and prevent us from realizing the anticipated benefits of operating our LNG tanker fleet. Deliveries may be delayed or cancelled due to, among other things, quality, warranty, or engineering issues, failure to meet contractual specifications, changes in governmental regulations or maritime standards, delays in equipment delivery by third-party suppliers, labor disruptions, shipyard capacity constraints, bankruptcy or liquidity issues of shipbuilders or sellers, political or economic disturbances in the country or region where vessels are constructed, weather or catastrophic events, shortages of construction materials such as steel, or our inability to satisfy payment or other contractual obligations. In addition, third parties from whom we charter LNG tankers may in the future fail to deliver vessels on time or at all, which could adversely affect our operations.
Our contracts for newbuild LNG tankers subject us to counterparty and cost-increase risks. The final cost of LNG tankers may increase pursuant to adjustment provisions in our contracts, and if we fail to make required payments, we could experience delivery delays, defaults under our acquisition agreements or the loss of rights to
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acquire vessels and amounts previously paid. Any delay in, or shortfall relating to, the construction of our LNG tanker fleet could require us to charter third-party vessels at potentially higher costs and on less favorable terms, which could have a material adverse effect on our business, contracts, financial condition, results of operations, cash flows, liquidity and prospects. In addition, the contracts for newly built vessels subject us to counterparty risk. The ability and willingness of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control, including, among other things, general economic conditions, the condition of the LNG shipping industry, the overall financial condition of our counterparty, prevailing prices for LNG cargos, rates received for specific types of LNG tankers, and various expenses. If our counterparties fail to meet their obligations to us or attempt to renegotiate our agreements, if our counterparties fail to deliver an LNG tanker in accordance with the terms of the relevant contract, or if a counterparty otherwise fails to honor its obligations to us under a contract, we could sustain significant losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Delays in the delivery, or shortfalls in the construction and acquisition of, our LNG tanker fleet, could require us to charter third-party LNG tankers, which could expose us to additional liability and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Management and operation of our LNG tanker fleet and the charter of third-party vessels involve significant risks.
In addition to the seven newbuild LNG tankers that have been delivered and are already in operation, we have entered into contracts to acquire two additional LNG tankers that are currently under construction and will be delivered on a rolling basis in 2026, which will be used to provide additional optionality to short-, medium- or long-term customers and to service our single existing post-COD DPU SPA and any future SPAs where LNG is sold on a delivered basis. Following delivery of each of these LNG tankers, we plan to manage and operate such tankers through our subsidiaries. In addition, we have chartered, and anticipate that we will continue to charter, LNG tankers to supplement our wholly-owned fleet. We have been building our team to manage and operate our fleet of LNG tankers, and as a result we are exposed to various operational risks as we continue to expand that team and grow our fleet of LNG tankers. We are also exposed to operational risks where we charter third-party vessels. For example, we are exposed to the following risks with respect to the operation of LNG tankers:
• the Company’s limited track record with managing and operating our own LNG tanker fleet;
• performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;
• breakdowns or failures of equipment or shortages or delays in the delivery of supplies;
• risks related to operators and service providers of tanker or tugs used in our operations;
• operational errors by us or any contracted facility, port or other operator of related infrastructure.
• failure to maintain the required government or regulatory approvals, permits or other authorizations;
• accidents, fires, explosions or other events or catastrophes;
• a lack of adequate and qualified personnel to adequately crew and operate the LNG tankers;
• potential labor shortages, work stoppages or labor union disputes;
• our potential inability to recruit and retain a team to manage and operate our fleet of LNG tankers and any chartered third-party vessels;
• weather-related or natural disasterinterruptions of operations;
• pollution, release of or exposure to toxic substances or environmental contamination, including marine accidents and spills, affecting operations;
• inability, or failure, of any counterparty to any fleet-related agreements to perform their contractual obligations; and
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• a lack of demand for shipping services by our customers after we receive delivery of our LNG tankers or charter a third-party vessel.
The risks related to the management and operation of LNG tankers are complex and technically challenging and subject to mechanical risks and problems. In particular, marine LNG operations are subject to a variety of risks, including, among others, marine disasters, piracy, bad weather, mechanical failures, environmental accidents, epidemics, grounding, fire, explosions and collisions, human error, and war and terrorism. An accident involving our cargos or any of our LNG tankers or chartered third-party vessels could result in death or injury to persons, loss of property or environmental damage; delays in the delivery of cargo; loss of revenues; governmental fines, penalties or restrictions on conducting business; higher insurance rates; and damage to our reputation and customer relationships generally. Any of these circumstances or events could increase our costs or lower our revenues.
If our LNG tankers, or any vessels we charter, sufferdamage as a result of such an incident, they may need to be repaired. Repairs and maintenance costs for LNG tankers are difficult to predict and may result in higher than anticipated operating expenses or require additional time or capital expenditures. The loss of earnings or costs to charter replacement tankers while these LNG tankers are being repaired could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. In addition, if one of our LNG tankers, or any vessels we charter, were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage and potential liability, including regulatory penalties, sanctions, fines and litigation, could have a material adverse effect on our reputation, our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. An accident involving one of our LNG tankers would also distract our management team.
We expect our offshore operating expenses to depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control. Other factors, such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements, could also increase operating expenditures.
If we fall short of our goals in acquiring or maintaining our LNG tanker fleet, we may be required to charter additional vessels from third parties. Additionally, our ability to charter vessels from third parties could be affected by potential shortages of LNG tankers worldwide. See —Risks Relating to the LNG Industry—There may be shortages of LNG tankers worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. As the overall trends steer toward more regulation and more stringent operating requirements, we are subject to the risk that our LNG tankers, or any chartered vessels we employ could fall out of compliance with such regulations. The terms of any charter agreement into which we may enter to substitute for shortfalls in our own LNG tanker fleet may require that we bear some or all of the associated costs with maintaining compliance with such regulations. While we believe we are appropriately situated to minimize this risk given the building of our own LNG tanker fleet, we cannot assure you that such factors will not have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Future occurrences of any of the foregoing or any other events of a similar or dissimilar nature could have a material adverse impact on our business, financial condition and results of operations.
The construction of our projects, and our operations, are subject to significant hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The construction and operation of our projects is and will be subject to the inherent risks associated with these types of operations, including the following:
• explosions, pollution, releases of toxic substances;
• fires, hurricanes and adverse weather conditions and other weather-related interruptions of construction and/or operations;
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• facilities performing below expected levels of efficiency;
• breakdown, failures or mechanical issues affecting our equipment;
• operational errors by vessel or tug operators;
• operational errors by us or any contracted facility operator; and
• labor disputes.
The occurrence of any of these events could require us, or enable our counterparties, to declare a force majeure under our material construction contracts or other construction contracts or SPAs or otherwise could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We may enter into certain arrangements to share the use and operations of facilities among projects, which would require us to meet certain conditions under our project-level financing documents. Despite the protection provided by such financing documents, the nature of such sharing arrangements is not currently known and may limit our operational flexibility, use of land and/or facilities.
We are permitted under certain of our project-level financing documents to enter into sharing arrangements with one or more entities that are developing or own one or more liquefaction trains and related facilities among our various projects. Such sharing arrangements may involve sharing the use and capacity of land and facilities with such adjacent project owners, including pooling the capacity of liquefaction trains, sharing common facilities, such as power generating facilities, storage tanks and berths, and sharing capacity of the pipeline interconnections, to the extent permitted under the relevant financing documents. We may also, subject to regulatory approvals, transfer and/or amend previously obtained permits and other authorizations or applications such that they may be used by such other project owners with which we may have sharing arrangements.
As future arrangements that would only be fully determined if the circumstances arise, there is uncertainty as to the full scope and impact of these sharing arrangements. Our project-level financing documents require us to meet certain conditions in respect of such sharing arrangements. These sharing arrangements would be subject to quiet enjoyment rights for the relevant project owners.
Risks Relating to Intellectual Property, Data Privacy and Cybersecurity
Hostile cyber intrusions, or other issues with our information technology, could severelyimpair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have a material adverse effect on our business.
Our projects and any other natural gas liquefaction and export facilities (including any expansion of existing facilities) we may decide to develop in the future include assets deemed by FERC to constitute critical energy infrastructure, the operation of which is dependent on our information technology, or IT, systems. The IT systems that run our natural gas liquefaction and export facilities are not completely isolated from external networks. A successful cyber-attack on the systems that will control our assets could severelydisrupt business operations, preventing us from serving customers or collecting revenues, as well as expose us to other risks. Additionally, a successful cyber-attack against a pipeline which supplies our LNG facilities could affect our ability to obtain physical delivery of sufficient natural gas to operate at full capacity, or at all.
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Other exposure to various types of cyber-attacks, such as malware, ransomware, viruses, denial of service attacks, social engineering, password spraying, credential stuffing, phishing or other malicious or fraudulent acts, as well as human error or malfeasance, could also potentially disrupt our operations. Artificial intelligence, or AI, both expands the attack surface and arms adversaries with more sophisticated tools for attacks, escalating the scale and unpredictability of cyber threats. Risks include AI-amplified attacks, third-party vendor vulnerabilities, and data breaches/unauthorized access. Such security threats are increasing in frequency and sophistication and pose a risk to the security of our IT systems and the confidentiality, availability and integrity of the information we process and maintain. We also may be vulnerable to interruption and breakdown by fire, natural disaster, power loss, telecommunication failures, internet failures and other catastrophic events. We may experience occasional system interruptions and delays that make our IT systems unavailable or slow to respond, including the interaction of our IT systems with those of third parties.
Cybersecurity threats are persistent and evolve quickly, and we may in the future experience such threats. Such threats have increased in frequency, scope and potential impact in recent years because of the proliferation of new technologies, including artificial intelligence, and the increased number, sophistication and activities of perpetrators of cyber-attacks. Since the techniques used to obtain unauthorized access to or to sabotage IT systems change frequently and are often not recognized until after they are launched against a target, we may be unable to anticipate these techniques or to implement adequate preventative measures. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation and customer relationships. We maintain and update a cybersecurity program to safeguard our IT systems, including those that run and connect to IT systems that run our natural gas liquefaction and export facilities. Failure to continue to do so effectively could expose our IT systems to increased risk of a successful cyber-attack.
We are also reliant on the security practices of our third-party service providers, business partners, vendors, and suppliers, which may be outside of our direct control. These third parties, and the services provided by these third parties, which may include cloud-based services, are subject to the same risk of experiencing, and have experienced, outages, other failures and security breaches described above. IT systems provided by third parties on which we rely also may be difficult to integrate with other tools due to their complexity, resulting in high data inconsistency and incompatibility. If these third parties fail to adhere to adequate security practices, or experience a breach of their systems, the information of our employees, consumers and business associates may be improperly accessed, used, disclosed or otherwise processed, and we may potentially be held liable, or alleged to be liable, under certain laws or contractual obligations for the acts or omissions of our third-party providers. Any loss or interruption to our IT systems or the services provided by third parties could adversely affect our business, financial condition and results of operations.
We maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity incidents. However, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available as discussed under —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. As a result, a significant cyber incident involving our business or operational control systems or related infrastructure, or that of third-party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting or otherwise disrupt our business. These impacts could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Changes in laws, rules or regulations relating to data privacy and security, or any actual or perceived failure by us to comply with such laws, rules and regulations, or contractual or other obligations relating to data privacy and security, could adversely impact our business.
We are, and may increasingly become, subject to various laws, directives, industry standards, rules and regulations, as well as contractual obligations, related to data privacy and security in the jurisdictions in which we operate. The regulatory environment related to data privacy and security is increasingly rigorous, with new and
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constantly changing requirements, and is likely to remain uncertain for the foreseeable future. These laws, rules and regulations may be interpreted and applied differently over time and from jurisdiction to jurisdiction, and it is possible that they will be interpreted and applied in ways that may have a material adverse effect on our results of operations, financial condition and cash flows.
In the United States, various federal and state regulators, including governmental agencies like the Federal Trade Commission, have adopted, or are considering adopting, laws, rules and regulations concerning personal information. Certain state laws may be more stringent or broader in scope, or offer greater individual rights, with respect to personal information than federal, international or other state laws, and such laws may differ from each other, all of which may complicate compliance efforts. A number of similar laws in other states have already taken effect or will become effective in the near future. State laws are changing rapidly and in the future Congress may pass a new comprehensive federal data protection law, which may add additional complexity, variation in requirements, restrictions and potential legal risks.
All of these evolving compliance and operational requirements impose significant costs on us, which are likely to increase over time. Any failure or perceived failure by us to comply with any applicable federal, state or similar foreign laws, rules and regulations relating to data privacy and security could result in damage to our reputation and our relationship with our customers, as well as proceedings or litigation by governmental agencies or individuals, including class action privacy litigation in certain jurisdictions, which could subject us to significant fines, sanctions, awards, penalties or judgments, operational changes, and negative publicity that could adversely affect our reputation, results of operations and financial condition.
If we are unable to obtain, maintain, protect and enforce our intellectual property rights, our business may be adversely affected.
We rely on a combination of intellectual property rights, including know-how and trade secrets, to establish, maintain and protect our intellectual property and other proprietary rights. For example, under our agreements with Baker Hughes, we own certain know-how and trade secrets relating to aspects of the liquefaction systems.
We cannot guarantee that our efforts to obtain, maintain, protect and enforce such rights are adequate or that we have secured, or will be able to secure, appropriate permissions or protections for all of the intellectual property rights we use or rely on. Furthermore, any such intellectual property rights may be challenged, invalidated, circumvented, infringed, misappropriated or otherwise violated. Any challenge to our intellectual property rights could result in them being narrowed in scope or declared invalid or unenforceable. In addition, other parties may independently develop technologies that are substantially similar or superior to ours and we may not be able to stop such parties from using such independently developed technologies to compete with us. If we fail to adequately obtain, maintain, protect and enforce our intellectual property rights, we may lose an important advantage in the markets in which we compete. While we seek to enter into confidentiality, intellectual property assignment and non-compete agreements, as applicable, with our employees, contractors and other third parties, we may fail to enter into such agreements with all relevant parties, such agreements may not be self-executing or enforceable, and we may be subject to claims that such parties have misappropriated the trade secrets or other intellectual property or proprietary rights of their former employers or other third parties. Additionally, these agreements may not provide meaningful protection for our trade secrets and know-how in the event of unauthorized use or disclosure.
We also may be forced to bring claimsagainst third parties to determine the ownership of what we regard as our intellectual property or to enforce our intellectual property against its infringement, misappropriation or other violation by third parties. Additionally, third parties may initiate legal proceedings alleging that we are infringing, misappropriating or otherwise violating their intellectual property rights. The outcomes of such intellectual property-related proceedings are often unpredictable. Regardless of whether any such proceedings are resolved in our favor, such proceedings could cause us to incur significant expenses and could distract our personnel from their normal responsibilities. Furthermore, our intellectual property rights and the enforcement or defense of such rights may be affected by developments or uncertainty in laws, rules and regulations related to intellectual property rights. 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.
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Risks Relating to Ownership of Our Class A Common Stock
VG Partners has significant influence over us, including control over decisions that require their approval, which could limit your ability to influence the outcome of key transactions, including a change of control.
Our Class B common stock has ten votes per share and our Class A common stock has one vote per share. Holders of shares of our Class B common stock will vote together with holders of our Class A common stock as a single class on all matters on which stockholders are entitled to vote generally, except as otherwise required by law. As of February 13, 2026, VG Partners owned 1,968,604,458 shares of Class B common stock or 100% of all shares of Class B common stock then outstanding. As a result, VG Partners holds approximately 97.6% of the combined voting power of our Class A common stock and our Class B common stock and is able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers or other extraordinary transactions. Further, the share of combined voting power held by VG Partners may increase in the future as a result of any repurchase of outstanding Class A common stock that we may decide to pursue from time to time, or any acquisition of our Class A common stock by VG Partners or our Founders, who control VG Partners (including upon vesting or exercise of equity awards). Furthermore, under Delaware law and our amended and restated certificate of incorporation and amended and restated bylaws, VG Partners is able to take certain actions by written consent of the majority of the combined voting power of our common stock without calling a meeting of stockholders. In addition, as the holder of a majority of the combined voting power of our common stock, VG Partners currently has the sole ability to elect the board of directors. Other holders of our Class A common stock, so long as they do not own a majority of the combined voting power, have only minority voting rights on matters affecting our business.
VG Partners may have interests that do not align with the interests of our other stockholders, including with regard to pursuing acquisitions, divestitures, and other transactions that, in their judgment, could enhance their equity investment, even though such transactions might involve risks to our other stockholders. VG Partners has effective control over our decisions to enter into such corporate transactions regardless of whether others believe that the transaction is in our best interests. Such concentration of voting control may have the effect of delaying, preventing, or deterring a change of control of us, could deprive stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of us, and might ultimately affect the market price of our Class A common stock.
There is the possibility of significant fluctuations in the price of our Class A common stock.
Many factors have in the past, and may in the future, cause the price of our Class A common stock to fluctuate substantially, which may limit or prevent investors from readily selling their shares of our Class A common stock and may otherwise negatively affect the liquidity of our Class A common stock. These factors include:
• the ongoing development and sustainability of an active, liquid market for our Class A common stock;
• the price of LNG and natural gas;
• the completion of the regulatory approval process required to construct and operate our projects and the timing of any such completion;
• the commencement and timely completion of construction of our projects;
• ongoing and threatened arbitration proceedings with some of our customers;
• our quarterly or annual earnings or those of other companies in our industry;
• actual or potential non-performance by any customer under any LNG sales contract that we may enter into;
• announcements by us or our competitors of significant contracts;
• changes in accounting standards, policies, guidance, interpretations or principles;
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• market conditions in the broader stock market in general, or in our industry in particular;
• future sales of our Class A common stock;
• investor perceptions of the investment opportunity associated with our Class A common stock relative to other investment alternatives;
• the public’s response to press releases or other public announcements or filings by us or third parties, including our filings with the SEC;
• regulatory developments;
• geopolitical developments;
• litigation and governmental investigations; and
• other factors described in these "Risk Factors" and elsewhere in this Form 10-K.
Accordingly, any investor may lose money or their investment in us and may be required to hold their shares for an indefinite period of time. In addition, when the market price of a stock has been volatile, holders of that stock frequently institute securities class action litigationagainst the company that issued the stock. For example, several putative class actions have been filed against us in connection with the IPO. See —Risk Factors—Risks Relating to Regulation and Litigation—We are involved, and may in the future become involved, in disputes and legal proceedings. We could incur substantial costs defending the class action and any other lawsuit our stockholders may bring against us. Such lawsuits could also divert the time and attention of our management from our business.
The trading market for our Class A common stock may also be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrade our stock, or if our results of operations do not meet their expectations, our stock price could decline.
If we become a United States real property holding corporation, or a USRPHC, non-U.S. shareholders may be subject to U.S. federal income tax in connection with the disposition of shares of our Class A common stock.
A non-U.S. holder of our Class A common stock not otherwise subject to U.S. federal income tax on gain from the sale or other disposition of our Class A common stock may nevertheless be subject to U.S. federal income tax with respect to such sale or other disposition if we are a USRPHC at any time within the five-year period preceding the sale or other disposition (or the non-U.S. holder’s holding period, if shorter). Generally, a U.S. corporation is a USRPHC if the fair market value of its “United States real property interests,” as defined in the Internal Revenue Code of 1986, as amended, or the Code, and applicable Treasury Regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. Based on the current composition of our assets, we believe that we are not currently a USRPHC. However, because (i) the determination of whether we are a USRPHC at any time depends on the fair market value of our U.S. real property relative to the fair market value of other business assets at such time, and (ii) the determination as to whether certain of our assets, including our property, plant and equipment, constitute United States real property interests, as defined in the Code, may be uncertain, there can be no assurance that we will not become a USRPHC at any point in time in the future. If we were to become a USRPHC at any point during the shorter of (i) the five-year period preceding the sale or other disposition and (ii) the non-U.S. holder’s holding period, and either (1) our Class A common stock is not regularly traded on an established securities market during the calendar year in which the sale or disposition occurs or (2) the non-U.S. holder has owned or is deemed to have owned, at any time within the relevant period, more than 5% of our Class A common stock, the non-U.S. holder would be subject to tax on the net gain from the sale or other disposition under the regular graduated U.S. federal income tax rates applicable to U.S. persons and could, under certain circumstances, be subject to withholding at a 15% rate on the amount realized.
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Certain provisions of our amended and restated certificate of incorporation, amended and restated bylaws and Delaware law have anti-takeover effects that could limit our ability to engage in certain strategic transactions our board of directors believes would be in the best interests of stockholders.
Certain provisions of our amended and restated certificate of incorporation and amended and restated bylaws could discourage unsolicited takeover proposals that stockholders might consider to be in their best interests. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws includes provisions that, among other things:
• provide for a classified board of directors with staggered three-year terms (except that prior to the Trigger Date, our board of directors will consist of a single class of directors each serving one year terms);
• permit directors to be removed from the board of directors by our stockholders only for cause and with the affirmative vote of at least 75% of the combined voting power of our then-outstanding common stock (except that prior to the Trigger Date, directors may be removed by our stockholders with or without cause);
• do not permit cumulative voting in the election of directors, which would otherwise allow less than a majority of stockholders to elect director candidates;
• authorize the issuance of “blank check” preferred stock without any need for action by stockholders;
• limit the ability of stockholders to call special meetings of stockholders or to act by written consent in lieu of a meeting (except that prior to the Trigger Date, special meetings of stockholders may be called by stockholders holding a majority of the combined voting power of our then-outstanding common stock and shareholder actions may be taken by written consent in lieu of a meeting);
• require the affirmative vote of at least 75% of the combined voting power of our then-outstanding common stock, voting as a single class, to amend certain provisions of our certificate of incorporation (except that prior to the Trigger Date, such amendments require only the affirmative vote of a majority of the outstanding shares of common stock); and
• establish advance notice requirements for nominations for election to our board of directors or for proposing matters that may be acted on by stockholders at stockholder meetings; provided that, at any time when VG Partners and its permitted transferees beneficially own, in the aggregate, at least 5% of the combined voting power of our common stock, such advance notice procedure will not apply to VG Partners and its permitted transferees.
The foregoing factors, as well as the significant common stock ownership by VG Partners, could impede a merger, takeover, or other business combination or discourage a potential investor from making a tender offer for our common stock, which, under certain circumstances, could reduce the market value of our Class A common stock.
In addition, we have expressly elected not to be governed by the “Business Combination” provisions of Section 203 of the Delaware General Corporation Law, or the DGCL, until the earlier of the time at which (i) VG Partners and its permitted transferees no longer beneficially own at least 15% of the combined voting power of our then-outstanding common stock and (ii) our board of directors determines that we will be subject to Section 203 of the DGCL and gives written notice to VG Partners that VG Partners and its permitted transferees shall not be subject to Section 203 of the DGCL. Section 203 of the DGCL generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any interested stockholder for a period of three years following the date on which the stockholder became an interested stockholder. If at any time we become subject to the provisions of Section 203 of the DGCL, these provisions will prohibit large stockholders, in particular a stockholder owning 15% or more of the outstanding voting power, from consummating a merger or combination with our company from a three-year period beginning on the date of the transaction in which the stockholder acquired in excess of 15% of our outstanding voting stock, unless this stockholder receives board approval for the transaction or 66 2 / 3 % of the combined voting power of our then-outstanding common stock not owned by the stockholder approve the merger or transaction. These provisions of Delaware law may have the effect of delaying,
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deferring or preventing a change in control, and may discourage bids for our Class A common stock at a premium over our market price.
We cannot guarantee that we will pay further dividends on our Class A common stock in the future and, consequently, your ability to achieve a return on your investment will depend on appreciation in the price of our Class A common stock.
While we have historically declared certain cash dividends and expect that we will declare and pay additional cash dividends on our common stock from time to time, we cannot guarantee that we will pay dividends on our Class A common stock in the future. The Company is a holding company and has no direct operations. All of our business operations are conducted through our subsidiaries. We cannot assure you that we will pay any dividend in the same amount or frequency as previous dividends, or at all, in the future. Any future dividend payments are within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, level of indebtedness, contractual restrictions with respect to payment of dividends, business opportunities, anticipated cash needs, provisions of applicable law and other factors that our board of directors may deem relevant. Consequently, your ability to achieve a return on any purchase of our Class A common stock could depend on the appreciation of our Class A common stock. Accordingly, you should not purchase shares of our Class A common stock with the expectation of receiving cash dividends.
Further, Delaware law requires that dividends be paid only out of “surplus,” which is defined as the fair market value of our net assets, minus our stated capital; or out of the current or the immediately preceding year’s earnings. In addition, our ability to pay dividends is subject to a range of restrictions and limitations set forth in the instruments governing our indebtedness and preferred equity.
If we, VG Partners or certain other stockholders sell shares of our Class A common stock or are perceived by the public markets as intending to sell them, the market price of our Class A common stock could decline.
The sale of substantial amounts of shares of our Class A common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our Class A common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell shares of our Class A common stock in the future at a time and at a price that we deem appropriate.
As of February 13, 2026, we had a total of 488,365,847 shares of our Class A common stock outstanding, of which 70,000,000 shares were sold in our IPO, and we had 224,879,858 outstanding stock options to purchase Class A common stock. All of the shares of our Class A common stock sold in our IPO are freely tradable without restriction or further registration under the Securities Act of 1933, as amended, or the Securities Act, by persons other than our “affiliates,” as that term is defined under Rule 144 of the Securities Act. All other shares of Class A common stock are eligible for resale in the public market, subject, in the case of shares held by our affiliates, to volume, manner of sale and other limitations under Rule 144.
In addition, as of February 13, 2026, an aggregate of 1,968,604,458 shares of our Class B common stock was outstanding, all of which was held by VG Partners. All such Class B shares of common stock are convertible into our Class A common stock on a one-to-one basis at any time at the option of the holder thereof. VG Partners continues to be considered an affiliate following our IPO, and accordingly shares of our Class A common stock issued upon conversion of our Class B common stock may not be sold in the absence of registration under the Securities Act unless an exemption from registration is available, including the exemptions contained in Rule 144.
VG Partners, as well as each other holder of shares of our common stock outstanding immediately prior to consummation of our IPO, will have the right, subject to certain exceptions and conditions, to require us to register their shares of Class A common stock under the Securities Act, and they will have the right to participate in future registrations of securities by us. Registration of any of these outstanding shares of common stock would result in such shares becoming freely tradable without compliance with Rule 144 upon effectiveness of the registration statement.
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We have also filed a registration statement on Form S-8 under the Securities Act to register shares of our Class A common stock issuable under our outstanding stock options to purchase Class A common stock and the shares of our Class A common stock reserved for issuance under the Venture Global, Inc. 2025 Omnibus Incentive Plan. Shares registered thereunder are available for sale in the open market. If such shares of Class A common stock are sold or it is perceived that they will be sold in the public market, the trading price of our Class A common stock could decline. These sales also could impede our ability to raise future capital.
You may be diluted by the future issuance of additional Class A common stock, including in connection with our incentive plans, acquisitions, conversion of our Class B common stock, or otherwise.
As of February 13, 2026, we had approximately 3.9 billion shares of Class A common stock authorized but unissued. Our amended and restated certificate of incorporation authorizes us to issue these shares of Class A common stock and options, rights, warrants and appreciation rights relating to Class A common stock for the consideration and on the terms and conditions established by our board of directors in its sole discretion, whether in connection with incentive plans, acquisitions or otherwise.
Additionally, shares of our Class B common stock are convertible into shares of our Class A common stock on a one-for-one basis at the option of the holder. Moreover, future transfers, except for certain permitted transfers described in our amended and restated certificate of incorporation, by VG Partners of shares of Class B common stock will generally result in those shares automatically converting into shares of Class A common stock on a one-for-one basis.
Any Class A common stock that we issue, including under our existing equity incentive plans or other equity incentive plans that we may adopt in the future and the conversion of Class B common stock into Class A common stock, would dilute holders of Class A common stock.
We cannot predict with certainty the size of future issuances of shares of our Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of shares of our common stock. Any such issuance could result in substantial dilution to our existing stockholders.
We may issue preferred stock whose terms could materially adversely affect the voting power or value of our Class A common stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our Class A common stock.
If our estimates or judgments relating to our critical accounting policies are based on assumptions that change or estimates that prove to be incorrect, our results of operations could be adversely affected, which could cause the price of our Class A common stock to decline.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements and the accompanying notes thereto. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets, liabilities, equity, revenue and expenses that are not readily apparent from other sources. It is possible that interpretation, industry practice and guidance involving our estimates and assumptions may evolve or change over
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time. If our assumptions change, or if actual circumstances differ from our assumptions, our results of operations may be adversely affected, which could cause the price of our Class A common stock to decline.
As a result of being a public company, we are obligated to develop and maintain proper and effective internal control over financial reporting, and any failure to maintain the adequacy of our internal control may adversely affect investor confidence in our company and, as a result, the value of our Class A common stock.
As a public company, we are required to commit significant resources and management time and attention to the requirements of being a public company, which causes us to incur significant legal, accounting and other expenses that we had not incurred as a private company, including costs associated with public company reporting requirements. We incur costs associated with the Securities Exchange Act of 1934, as amended, or the Exchange Act, the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Protection Act, and related rules implemented by the Securities and Exchange Commission, or the SEC, and the NYSE, and compliance with these requirements places significant demands on our legal, accounting and finance staff and on our accounting, financial and information systems.
We are required, pursuant to Section 404 of the Sarbanes-Oxley Act, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting for the fiscal year ending December 31, 2025. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. In addition, our independent registered public accounting firm will be required to attest to the effectiveness of our internal control over financial reporting in our Form 10-K required to be filed with the SEC for the fiscal year ending December 31, 2026. Our compliance with Section 404 of the Sarbanes-Oxley Act requires that we incur substantial expenses and expend significant management efforts. During 2025, we established an internal audit function, lead by a Chief Audit Executive, to compile the system and process documentation necessary to perform the evaluation needed to comply with Section 404 of the Sarbanes-Oxley Act.
During the evaluation and testing process of our internal controls, if we identify one or more material weaknesses in our internal control over financial reporting, we will be unable to certify that our internal control over financial reporting are effective. We cannot assure you that there will not be material weaknesses or significant deficiencies in our internal control over financial reporting in the future. Any failure to maintain internal control over financial reporting could severely inhibit our ability to accurately report our financial condition or results of operations. If we are unable to conclude that our internal control over financial reporting are effective, or if our independent registered public accounting firm determines we have a material weakness or significant deficiency in our internal control over financial reporting, we could lose investor confidence in the accuracy and completeness of our financial reports, the market price of our Class A common stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities. Failure to remedy any material weakness in our internal control over financial reporting, or to implement or maintain other effective control systems required of public companies, could also restrict our future access to the capital markets.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for exemptions from certain corporate governance requirements. If we rely on such exemptions in the future, you will not have the same protections afforded to stockholders of companies that are subject to such requirements.
VG Partners controls a majority of the voting power of our outstanding common stock, and as a result, we are a “controlled company” within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:
• a majority of the board of directors consist of independent directors;
• the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;
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• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
• there be an annual performance evaluation of the nominating and corporate governance and compensation committees.
Consistent with these exemptions, we do not have an independent compensation committee or an independent nominating and corporate governance committee. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware or the federal district courts of the United States of America, as applicable, as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which limits our stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or the Company’s directors, officers or other employees.
Our amended and restated certificate of incorporation provides that, unless we consent to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for: (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a breach of fiduciary duty owed by any current or former director, officer, stockholder or employee of the Company to the Company or our stockholders; (iii) any action asserting a claim against us arising under the Delaware General Corporation Law, or the DGCL, our certificate of incorporation or our bylaws or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware; or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine.
These provisions do not apply to suits brought to enforce a duty or liability created by the Exchange Act. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such claims. To prevent having to litigateclaims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, our amended and restated certificate of incorporation further provides that the federal district courts of the United States of America are the exclusive forum for resolving any complaint asserting a cause or causes of action arising under the Securities Act, including all causes of action asserted against any defendant to such complaint. While the Delaware courts have determined that such choice of forum provisions are facially valid, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in the exclusive forum provisions and there can be no assurance that these provisions will be enforced by a court in those other jurisdictions. In this regard, stockholders may not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder, including Section 22 of the Securities Act.
Any person or entity purchasing or otherwise acquiring any interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provision in our amended and restated certificate of incorporation. This choice-of-forum provision may limit a stockholder’s ability to bring a claim in a different judicial forum, including one that it may find favorable or convenient for a specified class of disputes with the Company or the Company’s directors, officers, other stockholders or employees, which may discourage such lawsuits. Alternatively, if a court were to find this provision of our amended and restated certificate of incorporation inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.
General Risk Factors
Global economic conditions, including inflation and supply chain disruptions, could continue to adversely affect our operations.
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General global economic downturns and macroeconomic trends, including heightened inflation, capital market volatility, interest rate and currency rate fluctuations, and economic slowdown or recession, may result in unfavorable conditions that could negatively affect demand for our products and exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Both domestic and international markets experienced significant inflationary pressures in fiscal years 2022 and 2023 and to combat such inflation, the Federal Reserve in the U.S. and other central banks in various countries raised interest rates in response. While the Federal Reserve began lowering interest rates in 2024 as inflation decreased, to the extent that inflationary pressures arise in the future, further interest rate increases or other government actions taken to reduce inflation could result in recessionary pressures in many parts of the world. Furthermore, currency exchange rates have been especially volatile in the recent past, and these currency fluctuations have affected, and may continue to affect, the reported value of our assets and liabilities, as well as our cash flows.
We have also experienced significant challenges in our global supply chain, including shortages in supply of materials and equipment to complete construction of our projects. While to date, we have been able to manage the challenges associated with these delays and shortages without significant disruption to our business, no assurance can be given that these efforts will continue to be successful. In addition, the deterioration of conditions in global credit markets may limit our ability to obtain, or may increase the cost of, external financing to fund our operations and capital expenditures on terms favorable to us, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us, when we require it, we will have to significantly reduce our spending, delay or cancel construction of our projects or substantially change our corporate structure, and we might not have sufficient resources to conduct or support our business as projected, which would have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. See —Risks Relating to Our Projects and Other Assets—We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.
Developments related to the ongoing war between Russia and Ukraine and the ongoing conflicts in the Middle East, as well as geopolitical instability in Venezuela, could adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Russia is one of the main players in the global oil and gas markets. Accordingly, any events that can impair or enhance its ability to compete in such markets are likely to have an impact on the industry in which we operate and the operations of our projects. Since the beginning of Russia’s invasion of Ukraine, sanctions have been imposed by Ukraine’s allies that seek to limit Russia’s ability to profit from oil and gas exports, and certain retaliatory measures have been taken by Russia in response (such as the ban on sales to certain countries). Additionally, there have been publicized threats to increase hacking activity against the critical infrastructure of any nation or organization that retaliatesagainst Russia for its invasion.
The Middle East remains a critical region for global energy production and ongoing and escalatingconflicts in the region—including armed hostilities involving Israel, Gaza, Iran and Iran-aligned groups in Lebanon and Gaza, including Hamas and Hezbollah—could adversely affect global energy markets. Such conflicts have resulted in, and could continue to result in, supply disruptions, damage to energy infrastructure, increased shipping and insurance costs, delays or rerouting of oil and gas cargos, heightened security risks, and increased volatility in oil and gas prices. Any material escalation or regional expansion of these conflicts could further disrupt global energy supply chains and trade flows and adversely affect market conditions relevant to our business.
Venezuela, a country estimated to hold the largest proven oil reserves in the world, has been subject to significant political, economic and social instability resulting from decades of underinvestment, infrastructure deterioration and the imposition of extensive international sanctions on its state-owned oil company. Recent events in Venezuela have raised the prospect of a potential increase in Venezuelan hydrocarbon production over the medium- to long-term. If such increased output were to materialize, the increase in oil supply could exert downward
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pressure on oil and other benchmark energy prices and alter regional supply dynamics, which in turn could affect global natural gas and LNG demand and prices.
In addition, the disruptions caused by the invasion of Ukraine, instability in the Middle East and Venezuela, and other geopolitical events have included, and may continue to include, political, social, and economic disruptions and uncertainties. Moreover, continued or escalating geopolitical conflicts, including those involving Russia, Ukraine, the Middle East and Venezuela, could contribute to sustained periods of elevated commodity price volatility (including material increases in certain commodity prices), shifting global supply patterns, reduced liquidity in energy markets and increased risk premiums in financial and commodity markets. Any prolonged, intensified or expanded conflict could materially disrupt international energy trade flows, constrain access to or the cost of imported energy and feedstock supplies, negatively impact demand for LNG and other energy commodities, and materially and adversely affect our competitive position, financial condition, results of operations and future growth prospects.
Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.
An act of terrorism, including an act of cyberterrorism, or military incident affecting LNG facilities, including our projects, may result in delays in construction, which could increase the cost of completion of our projects beyond the amounts that we have estimated. See —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. An act of terrorism, including an act of cyberterrorism, incident may also result in temporary or permanent closure of any of our projects, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism, including cyberterrorism, and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of an act of terrorism, including an act of cyberterrorism, war, earthquakes and other natural or man-made disasters, pandemics, credit crises, recessions or other factors could increase the cost of insurance coverage and could also result in a significant decline in the U.S. economy and could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Changes in tax laws or tax rulings, or the examination of our tax positions, could materially affect our financial condition and results of operations.
We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those with retroactive effect, could affect our tax obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. Our existing corporate structure and intercompany arrangements have been implemented in a manner we believe is in compliance with current prevailing tax laws. In addition, the taxing authorities in the United States and other jurisdictions where we do business regularly examine income and other tax returns and we expect that they may examine our income and other tax returns. The ultimate outcome of these examinations cannot be predicted with certainty. We continuously monitor and assess proposed tax legislation that could negatively impact our business.
We face risks related to the uncertainty regarding the future of international trade agreements and the United States’ position on international trade.
Certain policies and statements of the current Trump administration have given rise to uncertainty regarding the future of international trade agreements and the United States’ position on international trade. For example, in April 2025, the Trump administration announced broad reciprocal tariffs on imports from all countries. This
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included a 10% baseline tariff and higher country-specific tariffs, and resulted in some countries announcing additional retaliatory tariffs, or plans for retaliatory tariffs. While the U.S. Supreme Court issued a ruling against the
validity of such tariffs in February 2026, the Trump administration has announced the imposition of a new 15% baseline tariff under other legal authority and there is ongoing uncertainty in connection with tariff policies. The imposition and or threat of tariffs by the United States has in the past, and may continue to in the future, result in retaliatory tariffs imposed on U.S. businesses from any countries affected by such tariffs. Additionally, the imposition of retaliatory tariffs by any nation against the U.S. could have a material adverse effect on trade between the U.S. and other nations, as well as on the cost of goods for U.S. companies and consumers. The impact of any such tariffs remains uncertain and accordingly is not reflected in our current project cost estimates. However, t he impositions of such tariffs could negatively affect demand for our products and our project cost estimates, particularly construction costs that may relate to foreign-sourced materials such as steel and aluminum, and also exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity.
We also face potential exposure to evolving U.S. tariff standards, and potential retaliatory international tariffs that may be imposed by other countries in response to U.S. tariffs, primarily on LNG exports and construction-related materials, systems, piping and commodities (e.g. cement, copper, nickel and steel). China’s decision to continue to implement a 15% tariff on coal and LNG products in response to U.S. tariff initiatives may potentially impact our ability to sell commissioning and short-term LNG cargos to China. In addition, given the rapidly evolving and volatile tariff landscape, we cannot anticipate the breadth of potential tariffs that may be announced and/or implemented on internationally sourced components and commodities used to construct our LNG facilities. As a result, the impact of any such tariffs remains uncertain and accordingly is not reflected in our current project cost estimates. However, the imposition of any such tariffs could negatively affect demand for our products and our project cost estimates, and also exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash flow, financing requirements, and liquidity.
As of December 31, 2025, we had entered into post-COD SPAs for an aggregate of 9.5 mtpa with Chinese customers across all of our projects. Any future changes to the United States’ trade relationship with China or other major LNG importing nations, including through the imposition of further tariffs, could have an adverse impact on such SPAs and our ability to market the remaining production capacity of our projects, by reducing demand from such customers for U.S. LNG exports.
Moreover, various bilateral trade negotiations are ongoing and additional negotiations may take place, any of which could result in further changes to country-specific trade policies and tariffs. For example, the United States announced a framework trade deal in July 2025 pursuant to which certain European Union goods entering the United States would be subject to a 15% tariff, and the European Union would commit to make $750 billion of strategic energy purchases, covering oil, LNG and nuclear technology, during President Trump’s term in office. However, in February 2026, the European Parliament halted the ratification process in light of the U.S. Supreme Court ruling against the validity of tariffs and the subsequent tariffs announced by the Trump administration. There can be no assurance as to the outcome of any ongoing or additional negotiations, or as to the final terms of the trade deal with the European Union. The European Union is the largest provider of foreign-sourced equipment for our LNG construction projects by dollar value. Global economic uncertainty and any related reduction in economic activity or capital investment may slow growth in global GDP or lead to global recession. Accordingly, these tariffs and any retaliatory actions from other countries could have a material impact on our financial condition, results of operations and/or cash flows through reduced demand and competitiveness for both our long-term and short-term contract sales in countries that may be affected by those policies, and increased project costs for future imported equipment and materials.
The uncertainty regarding the policies of the current Trump administration with respect to the future of trade partnerships and relations, including the possibility of additional or increased tariffs, may reduce our competitiveness in countries that may be affected by those policies, such as China and the European Union, whether or not the current Trump administration ultimately takes any additional actions. Any of these factors could adversely affect our ability to market the remaining production capacity of our projects, which could have a material
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adverse effect on the viability of our projects and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
Our ability to use our net operating losses to offset future taxable income may be subject to certain limitations.
As of December 31, 2025, we have accumulated federal and foreign net operating loss, or NOL, carryforwards of $10.0 billion and $25 million, respectively, with an indefinite carryforward period. We additionally had accumulated state net operating loss carryforwards of approximately $3.4 billion, of which $42 million will expire by 2037. Under the current tax law, federal NOLs incurred in taxable years beginning after December 31, 2017, can be carried forward indefinitely, but the deductibility of such federal NOLs in taxable years beginning after December 31, 2020 is limited to 80% of taxable income. These federal and state NOLs may be available to offset income tax liabilities in the future. In addition, we may generate additional NOLs in future years. NOLs may be limited by separate return limitation year, or SRLY, rules. These rules generally limit the use of NOL carryforwards to the amount of taxable income that the NOL producing entity contributes to consolidated taxable income during the year. Of the federal NOL carryforward amount stated earlier, $23 million is currently subject to the SRLY rules. NOLs subject to the SRLY limitations may also be subject to Section 382 limitations described below.
In general, under Section 382 of the Code, or Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. For this purpose, an ownership change generally means a more than 50 percentage point change in the ownership of a corporation by one or more shareholders or specified groups of shareholders, each of which owns 5% or more of the corporation (determined after the application of certain attribution and grouping rules) over a three-year period. Although we do not believe that any of our NOLs are currently subject to limitation under Section 382, future changes in our stock ownership could result in an ownership change under Section 382, which could limit our ability to use our existing or future NOLs to offset future taxable income.
The outbreak of any infectious diseases or other illness could adversely impact our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.
We are subject to risks related to outbreaks of infectious diseases. The extent to which an outbreak of an infectious disease or other illness could impact our business, operations and financial results depends on numerous factors that we cannot accurately predict, including: the duration and scope of any infectious disease; governmental, business and individuals’ actions taken in response to any infectious disease and the associated impact on economic activity; the effect on the level of global demand for natural gas; geopolitical developments in the oil and gas markets; our ability to procure materials and services from third parties that are necessary for the operation of our business; the effect on the labor market, including worker shortages or related to supply chain disruptions; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill; and the ability of our customers to pay for our services if their businesses suffer as a result of any infectious disease.
We cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of any infectious disease or pandemic. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and a material adverse effect on our financial position and results of operations. Moreover, the foregoing factors may also have the effect of heightening some of the other risk factors described herein.
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Executive Summary
Our Financial Results .
Years ended December 31,
Income from operations
LNG volumes exported
Cargos
TBtu
LNG volumes sold (TBtu)
Weighted average price of LNG volumes sold (per MMBtu)
Liquefaction fee (1)
Commodity fee
Weighted average price of LNG volumes sold
(1) Includes sales prices indexed to foreign gas markets, exclusive of an implied commodity fee, and fixed liquefaction fees.
Our income from operations for the year ended December 31, 2025 increased compared to the prior year primarily due to higher sales volumes at our Plaquemines Project from the commencement of LNG production in December 2024 and continued ramp up of LNG production during 2025. This was partially offset by lower weighted average LNG sales prices at our Calcasieu Project due to the commencement of LNG sales under its post-COD SPAs and the higher cost of feed gas.
Our LNG Projects
Calcasieu Project . Our initial LNG export facility declared COD and commenced the sale of LNG to its customers under our post-COD SPAs on April 15, 2025. Prior to COD, the Calcasieu Project sold LNG under LNG Commissioning Sales Agreements.
Calcasieu Project
Years ended December 31,
LNG volumes exported
Cargos
TBtu
LNG volumes sold (TBtu)
Weighted average price of LNG volumes sold (per MMBtu)
Fixed liquefaction fee
Commodity fee
Weighted average price of LNG volumes sold
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Plaquemines Project . Production and sales of LNG from our second LNG export facility increased during the period while physical construction and the commissioning program of the project continued to advance. During the year ended December 31, 2025, we incurred $3.9 billion of project costs, the majority of which were capitalized, and we placed an additional $13.4 billion of assets in service in accordance with the applicable accounting guidance.
Plaquemines Project
Years ended December 31,
LNG volumes exported
Cargos
TBtu
LNG volumes sold (TBtu)
Weighted average price of LNG volumes sold (per MMBtu)
Fixed liquefaction fee
Commodity fee
Weighted average price of LNG volumes sold
CP2 Project . In June 2025, we commenced site work on our third LNG export facility, 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 $15.1 billion in project financing to fund the development and construction of Phase 1 of the CP2 Project. During the year ended December 31, 2025, we incurred $6.5 billion of project costs primarily associated with construction activities and purchases of equipment procurement, of which $6.3 billion was capitalized and $203 million was expensed.
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.
Our Strategic Developments . In 2025, we formally initiated the development process for the Plaquemines Expansion Project with expected annual peak production capacity of 31.0 mtpa. See I tem 1A.— Business for further discussion.
We took delivery of four LNG tankers during the year ended December 31, 2025, and one LNG tanker in the first quarter of 2026. This brought our total owned fleet of LNG tankers to seven with an additional two LNG tankers that are currently under construction and will be delivered in 2026. In 2025, we used our LNG tankers to transport 61 cargos from our LNG facilities.
VGLNG Sources of Capital . In January 2025, we completed our IPO, issuing 70 million shares of our Class A common stock at a public offering price of $25.00 per 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.
In September 2025, Blackfin entered into the Blackfin Credit Facilities totaling $1.6 billion. Proceeds from the Blackfin Credit Facilities were used to reimburse $889 million to VGLNG for prior expenditures related to the development and construction of the Blackfin Pipeline.
In November 2025, VGLNG entered into the VGLNG Revolving Credit Facility totaling $2.0 billion. Proceeds from the VGLNG Revolving Credit Facility will be used for general corporate purposes of VGLNG and its subsidiaries.
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Key Factors Affecting Results of Operations
The key factors affecting our results of operations and financial performance are as follows:
LNG Sales. We sell LNG throughout 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.
LNG pricing structure. 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 both 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 a transportation charge and is indexed to foreign gas markets, such as TTF or JKM.
Sales of LNG during commissioning. We generally sell LNG produced during the commissioning phase of our projects, prior to COD, on a forward spot or short-term contracted basis. Our ability to generate cash proceeds from the sale of commissioning LNG, and the amount of any such cash proceeds, depends 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, as well as the market price for LNG at the time such sales are executed. As a result, the amount of cash proceeds we are able to generate from the sale of commissioning LNG will likely differ from period to period and from project to project, and such differences could be material.
Sales of Contracted LNG. We sell LNG under post COD-SPAs and Firm-start SPAs leveraging a combination of long-term 20-year Contracted SPAs as well as short- and medium-term Contracted SPAs to optimize the average fixed liquefaction fee across our SPAs. Our ability to generate revenue, and the amount of any associated 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 fixed liquefaction 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 excess LNG. We sell LNG produced above our Contracted SPA commitments under short‑, medium‑, or long‑term arrangements, providing commercial and pricing flexibility. Our ability to generate cash proceeds from such sales, and the amount of any such revenue 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 and the market price for LNG at the time such sales are executed. As a result, the amount of revenue and cash proceeds we are able to generate from the sale of uncommitted 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 are the primary component of our cost of sales. Under our Contracted SPAs and substantially all of our commissioning LNG sales executed to date, our customers pay a fixed liquefaction fee (which includes a CPI-linked component) per MMBtu, plus a variable commodity fee 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.
Project costs and development expenses . We currently have greenfield and expansion projects in various stages of construction and development. We expect our development, construction and commissioning costs 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
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outside of our control, which could lead to higher development, construction and commissioning costs for our projects.
Operating costs . We expect to increase our project‑dedicated staff as we commence operations at our facilities. As a result, we anticipate that operating and maintenance expenses will increase significantly as we continue commissioning and operation of our 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. Once projects commence 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. 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, 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 our greenfield and expansion 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 our Contracted SPAs and sales by VG Commodities that include a fixed liquefaction fee will only be partially adjusted for inflation over the contract term, as is the case with certain of our existing Contracted SPAs. In addition, we anticipate that our operating costs will experience inflationary pressure over 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 after our facilities achieve their respective CODs. We have already begun experiencing, and we expect to continue to 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.
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Macroeconomic Trends . Macroeconomic conditions, such as high inflation, 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.
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Results of Operations
Year ended December 31, 2025 compared to year ended December 31, 2024
The following table shows a summary of our results of operations for the periods indicated:
Years ended December 31,
Change
REVENUE
OPERATING EXPENSE
Cost of sales (exclusive of depreciation and amortization shown separately below)
Operating and maintenance expense
General and administrative expense
Development expense
Depreciation and amortization
Total operating expense
INCOME FROM OPERATIONS
OTHER INCOME (EXPENSE)
Interest income
Interest expense, net
Gain (loss) on interest rate swaps
Loss on financing transactions
Loss on foreign currency transactions
Total other income (expense)
INCOME BEFORE INCOME TAX EXPENSE
Income tax expense
NET INCOME
Less: Net income attributable to redeemable stock of subsidiary
Less: Net income attributable to non-controlling interests
Less: Dividends on VGLNG Series A Preferred Shares
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS
NM Percentage not meaningful.
Revenue
Revenue was $13.8 billion for the year ended December 31, 2025, an $8.8 billion, or 177%, increase from $5.0 billion for the year ended December 31, 2024. This increase was primarily due to $10.1 billion from higher LNG sales volumes primarily at the Plaquemines Project due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025. This increase was partially offset by lower LNG sales prices of $1.3 billion primarily at the Calcasieu Project after COD in April 2025, partially offset by higher LNG sales prices prior to COD in April 2025.
Gross proceeds, before deducting the cost of feed gas, attributable to Test LNG sales generated prior to the Plaquemines Project facilities being in service from an accounting perspective, and therefore recognized as an adjustment to construction in progress and not as revenue, were $132 million for the year ended December 31, 2025.
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Operating Expense
Cost of Sales
Cost of sales was $5.9 billion for the year ended December 31, 2025, a $4.6 billion increase from $1.4 billion for the year ended December 31, 2024. This increase was due to
• $3.8 billion from higher LNG sales volumes primarily at the Plaquemines Project due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025;
• $609 million due to higher costs of feed gas primarily at the Calcasieu Project; and
• $123 million unfavorable change in the fair value of our natural gas supply contracts.
Costs attributable to the production of Test LNG sales, primarily consisting of the cost of feed gas, incurred prior to the Plaquemines Project facilities being in service from an accounting perspective, and therefore recognized as an adjustment to construction in progress and not as cost of sales, was $63 million for the year ended December 31, 2025.
Operating and Maintenance Expense
Operating and maintenance expense was $975 million for the year ended December 31, 2025, a $386 million, or 66%, increase from $589 million for the year ended December 31, 2024. This increase was primarily due to $265 million in higher operating costs in support of the ramp up of LNG production at the Plaquemines Project due to an increase in non-capitalizable personnel costs, commissioning work, and operational insurance costs, as well as $175 million in higher operating costs for our LNG tankers. These increases were partially offset by a $77 million reduction in operating costs at the Calcasieu Project primarily due to lower commissioning and remediation work.
General and Administrative Expense
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. This increase was primarily due to increased personnel costs of $82 million due to higher employee headcount, as well as increased non-personnel costs of $38 million primarily due to increases in legal and other professional service fees, IT and insurance costs.
Development Expense
Development expense was $344 million for the year ended December 31, 2025, a $291 million, or 46%, decrease from $635 million for the year ended December 31, 2024. This decrease was primarily due to lower development costs that were expensed of $282 million as a result of the CP2 Project being declared probable during 2025, and the majority of the costs to develop the facility subsequently being capitalized.
Depreciation and Amortization
Depreciation and amortization was $941 million for the year ended December 31, 2025, a $619 million, or 192%, increase from $322 million for the year ended December 31, 2024. This increase was primarily due to placing a portion of the Plaquemines Project assets in service from an accounting perspective starting in December 2024 and throughout 2025 and placing additional LNG tankers in service throughout 2025. This increase was partially offset by a decrease of $46 million at the Calcasieu Project primarily due to an extension of the estimated useful lives of certain LNG facility assets in 2025 to align with the extended remaining terms of certain land leases to which the LNG facility assets are affixed.
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Income from Operations
Income from operations was $5.2 billion for the year ended December 31, 2025, a $3.4 billion, or 192%, increase from $1.8 billion for the year ended December 31, 2024. This increase was the result of higher revenue due to increased sales volumes, primarily at the Plaquemines Project, partially offset by lower weighted average LNG sales prices, at the Calcasieu Project subsequent to COD in April 2025, and lower development expense. These were partially offset by, higher cost of sales due to increased volumes and the cost of feed gas, higher depreciation expense, and higher operating and maintenance expense, as discussed above.
Other Income or Expense
Interest Income
Interest income was $151 million for the year ended December 31, 2025, a $93 million, or 38%, decrease from $244 million for the year ended December 31, 2024. This decrease was primarily due to lower average cash balances and interest rates during the year ended December 31, 2025, compared to the year ended December 31, 2024.
Interest Expense, Net
Interest expense, net was $1.5 billion for the year ended December 31, 2025, a $870 million, or 149%, increase from $584 million for the year ended December 31, 2024. This increase was primarily due to higher non-capitalizable interest costs due to placing a portion of the Plaquemines Project assets in service in accordance with the applicable accounting guidance and an increase in our average outstanding debt.
Gain (Loss) on Interest Rate Swaps
Loss on interest rate swaps was $220 million for the year ended December 31, 2025, a $994 million, or 128%, unfavorable change from a gain on interest rate swaps of $774 million for the year ended December 31, 2024. This unfavorable change was primarily due to a decrease in the forward interest rate curves during the year ended December 31, 2025, compared to an increase during the year ended December 31, 2024, resulting in the following:
• a $908 million unfavorable change on the Plaquemines Project interest rate swaps, which were partially settled during the year ended December 31, 2025;
• a $66 million unfavorable change on the CP2 Project interest rate swaps, which were entered into in 2025; and
• a $33 million unfavorable change on the Calcasieu Project interest rate swaps.
These were partially offset by a $13 million favorable change on the Blackfin Credit Facility interest rate swaps, which were entered into in the fourth quarter of 2025.
Loss on Financing Transactions
Loss on financing transactions was $267 million for the year ended December 31, 2025, a $253 million increase from $14 million for the year ended December 31, 2024. This increase was due to the write-off of debt issuance costs associated with the partial prepayment of the Plaquemines Construction Term Loan and the prepayment of CP2 Bridge Facilities during the year ended December 31, 2025, as compared to the write-off of debt issuance costs associated with the full prepayment of the Plaquemines Equity Bridge Facility during the year ended December 31, 2024.
Loss on Foreign Currency Transactions
Loss on foreign currency transactions was $3 million for the year ended December 31, 2025.
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Income before Income Tax Expense
Income before income tax expense was $3.4 billion for the year ended December 31, 2025, a $1.2 billion, or 54%, increase from $2.2 billion for the year ended December 31, 2024. This increase was primarily a result of an increase in income from operations, partially offset by an unfavorable change in the gain (loss) on interest rate swaps, higher interest expense and and higher loss on financing transactions, as discussed above.
Income Tax Expense
Income tax expense was $630 million for the year ended December 31, 2025, a $193 million, or 44%, increase from $437 million for the year ended December 31, 2024, primarily driven by an increase in income before income tax expense, discussed above, partially offset by a change in our effective tax rate. Our effective tax rate was 18.7% for the year ended December 31, 2025, compared to 20.0% for the year ended December 31, 2024. The 2025 effective tax rate was impacted primarily by the recognition of stock option windfall tax benefits, research and development tax credits, as well as a combination of non-deductible expenses and changes in the valuation allowance against certain deferred tax assets.
Net Income
Net income was $2.7 billion for the year ended December 31, 2025, a $1.0 billion, or 57%, increase from $1.7 billion for the year ended December 31, 2024. This increase was primarily the result of an increase in income before income tax expense, partially offset by higher income tax expense, as discussed above.
Net Income Attributable to Redeemable Stock of Subsidiary
Net income attributable to redeemable stock of subsidiary was $167 million for the year ended December 31, 2025, a $23 million, or 16%, increase from $144 million for the year ended December 31, 2024. This increase was due to higher paid-in-kind distributions on the CP Funding Redeemable Preferred Units.
Net Income Attributable to Non-controlling Interests
Net income attributable to non-controlling interests was $36 million for the year ended December 31, 2025, a $23 million, or 39%, decrease from $59 million for the year ended December 31, 2024. This decrease was primarily due to the allocation of earnings to the Calcasieu Holdings Class B common unit holders based on ownership interests subsequent to COD of the Calcasieu Project.
Dividends on VGLNG Series A Preferred Shares
Dividends on VGLNG Series A Preferred Shares were $270 million for the year ended December 31, 2025, a $202 million, or 297%, increase from $68 million for the year ended December 31, 2024. This increase was due to the issuance of the VGLNG Series A Preferred Shares in late September 2024 and the corresponding difference in the accumulation of dividends.
Net Income Attributable to Common Stockholders
Net income attributable to common stockholders was $2.3 billion for the year ended December 31, 2025, a $0.8 billion, or 53%, increase from $1.5 billion for the year ended December 31, 2024. This increase was primarily the result of the changes discussed above.
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Segment Results of Operations
We have four reportable segments, which consist of the Calcasieu Project, the Plaquemines Project, the CP2 Project, and our sales and shipping business. Each LNG project includes activity of both the respective liquefaction facility and export terminal and the associated pipeline(s) that will supply the natural gas to that facility. Our sales and shipping business is engaged in the sale and delivery of LNG to our customers and includes the operating costs associated with our fleet of LNG tankers. Activities reported in corporate, other and eliminations include immaterial operating segments, overhead costs not directly associated with our reportable segments (for example, general and administrative and marketing expenses), and inter-segment eliminations. Prior period presentations have been reclassified to conform to the current segment reporting structure to separately disclose our sales and shipping business that is now quantitatively material.
Year ended December 31, 2025 compared to year ended December 31, 2024
The following table shows a summary of our segment income (loss) from operations for the periods indicated:
Years ended December 31,
Change
Calcasieu Project
Plaquemines Project
CP2 Project
Sales and shipping
Corporate, other and eliminations
Total
NM Percentage not meaningful.
Calcasieu Project
For the year ended December 31, 2025, the Calcasieu Project had income from operations of $1.3 billion, a $1.5 billion, or 53%, decrease from $2.8 billion for the year ended December 31, 2024.
This decrease was primarily due to:
• an increase in cost of sales of $835 million due to higher costs of feed gas of $685 million, an increase in LNG sales volumes of $101 million, and an unfavorable change in fair value of natural gas supply contracts of $49 million; and
• a decrease in revenue of $791 million due to:
◦ a net decrease of $1.2 billion due to lower LNG sales prices after COD in April 2025 offset by higher LNG sales prices prior to COD in April 2025, partially offset by
◦ an increase in LNG sales volumes of $375 million.
These decreases were partially offset by:
• a decrease in operating and maintenance expense of $77 million due to lower commissioning and remediation work; and
• a decrease in depreciation and amortization expense of $46 million due to an extension of the estimated useful lives of certain LNG facility assets in 2025 to align with the extended remaining terms of certain land leases to which the LNG facility assets are affixed.
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Plaquemines Project
For the year ended December 31, 2025, the Plaquemines Project had income from operations of $4.2 billion, a $4.4 billion increase from a loss from operations of $217 million for the year ended December 31, 2024.
This increase was primarily due to:
• an increase in revenue of $9.2 billion from higher LNG sales volumes due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025.
This increase was partially offset by:
• an increase in cost of sales of $3.8 billion from higher LNG sales volumes due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025;
• an increase in depreciation and amortization expense of $597 million due to placing a portion of the Plaquemines Project assets in service from an accounting perspective starting in December 2024 and throughout 2025; and
• an increase in operating and maintenance expense of $265 million primarily due to higher operating costs in support of LNG production including higher non-capitalizable personnel costs, commissioning work, and operational insurance costs.
CP2 Project
For the year ended December 31, 2025, the CP2 Project had a loss from operations of $278 million, a $222 million, or 44%, decrease from $500 million for the year ended December 31, 2024. This decrease was primarily driven by lower engineering and development costs that were expensed of $282 million as a result of the CP2 Project being declared probable during 2025, and the majority of the costs to develop the facility subsequently being capitalized.
Sales and shipping
For the year ended December 31, 2025, our sales and shipping business had income from operations of $248 million, a $268 million increase from a loss from operations of $20 million for the year ended December 31, 2024.
This increase was primarily due to:
• an increase in revenue of $2.2 billion generated from the sale of LNG produced by our LNG facilities and sold through our sales and shipping business, primarily due to an increase in LNG sales volumes.
This increase was partially offset by:
• an increase in cost of sales of $1.7 billion due to the cost of LNG purchased from our LNG facilities and sold by our sales and shipping business, primarily due to an increase in LNG sales volumes;
• an increase in operating and maintenance expense of $175 million due to increased operating costs for our LNG tankers; and
• an increase in depreciation and amortization expense of $30 million due to placing additional LNG tankers in service in 2025.
Corporate, other and eliminations
For the year ended December 31, 2025, corporate, other and eliminations had a loss from operations of $358 million, a $45 million, or 14%, increase from $313 million for the year ended December 31, 2024.
This increase was primarily due to:
• an increase in general and administrative expense of $100 million primarily due to higher employee headcount and increases in legal and other professional service fees, IT and insurance costs; and
• an increase in depreciation and amortization expense of $39 million primarily due to placing additional assets in service throughout 2025.
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These increases were partially offset by:
• the impact of inter-segment eliminations of $86 million for intercompany purchases and sales of LNG between our sales and shipping business and our LNG facilities.
Liquidity and Capital Resources
General
We have been generating proceeds from the sale of LNG since the first quarter of 2022. We may incur significant costs as we continue to develop our existing and other potential natural gas liquefaction and export projects, p ipeline infrastructure projects, and other complementary gas transportation projects and activities .
Funding Requirements
The operation, commissioning, construction and development of our projects requires significant capital expenditures. We expect that operating costs at our projects will be funded with cash proceeds generated by the sale of LNG.
Plaquemines Project. Approximately $0.6 billion to $1.0 billion of the current estimated Total Project Cost for the Plaquemines Project, has yet to be paid as of December 31, 2025. We believe the Plaquemines Project will have sufficient access to cash, including proceeds from commissioning sales, to fund its operations and complete the project.
CP2 Project . We currently estimate that the Total Project Cost for Phases 1 and 2 of the CP2 Project will be approximately $32.5 billion to $33.5 billion. Approximately $9.9 billion of the Total Project Cost for Phases 1 and 2 of the CP2 Project has been paid as of December 31, 2025. We believe the CP2 Project will have sufficient access to cash from the CP2 Construction Term Loan and future proceeds from commissioning LNG sales to fund the construction and completion of Phase 1 of the project. We intend to finance the construction and development of Phase 2, including the related owners’ costs, through one or more sources of debt and equity financing.
Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary environment and the potential impact of tariffs in place as of December 31, 2025. This estimate is based upon the contracts that we have in place for the CP2 Project and our construction cost experiences with the Calcasieu Project and the Plaquemines Project, as well as expected costs to construct longer pipelines for the CP2 Project than for the Calcasieu Project and the Plaquemines Project. The cost estimate for the CP2 Project reflects the current inflationary environment, and may be higher, potentially materially, compared to our current estimates as a result of many factors. Furthermore, our cost estimates might change due to factors such as unexpecteddelays in the construction or commissioning of our projects, the execution of any repair or warranty work and change orders or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for such projects, and/or other construction or supply contracts. For more details on these risks, 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.
These estimates do not reflect the potential impact of any changes to tariffs that have been announced or implemented since December 31, 2025 or that may be implemented in the future. They do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Our project budget estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025. Certain of our products, including our Baker Hughes sourced liquefaction train system modules and power island components, are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or
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the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects.
Greenfield and expansion projects. We intend to finance the construction and development of our future greenfield and expansion projects, including the related owners’ costs, through one or more sources of debt and equity financing. The amount of project-level equity funding that is required for any of our projects relative to the amount of project-level debt financing may differ between our projects. Generally, we expect to finance approximately 50% to 75% of the anticipated construction costs of each of our projects with project-level debt financing (which may include non-recourse or limited recourse debt), and the remaining 25% to 50% with project-level equity—which may consist of equity contributions by us, equity financing transactions, mezzanine financing and/or other similar financing alternatives. The final terms and availability of such debt and equity financings will depend on various factors, including market conditions at the time. We may consider alternative structures to raise capital for those projects and, as a result, there can be no assurance that the financing structure for our future greenfield and expansion projects will be similar to those used for our prior or current projects.
Contractual Obligations
We have contractual obligations involving commitments to third parties that impact our liquidity and capital resource needs. In addition to the construction and development obligations discussed above, the following table summarizes our contractual obligations as of December 31, 2025:
Years ended December 31,
Thereafter
Total
Operating contracts
Natural gas supply and transportation
Leases
Regasification capacity
Other
Other capital projects
LNG tankers
Pipeline development projects
Total
The Company has also entered into certain credit arrangements to secure the transportation of natural gas. As of December 31, 2025, the maximum undiscounted potential exposure associated with these arrangements was $260 million. This amount is not currently recognized as a liability on our consolidated balance sheet. To date, no amounts have been drawn against these arrangements.
In addition, we have significant debt and associated interest expense obligations at our subsidiaries. This consists of debt incurred by VGLNG as well as debt incurred by subsidiaries of VGLNG in connection with financing of various projects. We anticipate obtaining significant additional financing, and incurring related fees and interest, for the development of Phase 2 of the CP2 Project, our greenfield and expansion projects, our pipeline development projects, and our LNG tankers.
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Outstanding debt and associated interest obligations of the project-level subsidiaries of VGLNG have no recourse to nor are guaranteed by Venture Global or VGLNG. The following table summarizes our debt and associated interest obligations of project-level subsidiaries of VGLNG as of December 31, 2025:
Years ended December 31,
Thereafter
Total
Principal maturities (1)(2)
Interest payments (3)
Total
(1) Reflects aggregate contractual maturities for outstanding principal as of December 31, 2025. See —Funding Requirements and Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K, for more information.
(2) Excludes $1.7 billion of redeemable preferred shares of Calcasieu Pass Funding, presented as redeemable stock of subsidiary which is redeemable at the option of the holder thereof upon the occurrence of certain events. See Item 8.— Financial Statements and Supplementary Data — Note 17 – Redeemable Stock of Subsidiary of this Form 10-K.
(3) Inclusive of the expected settlements of interest rate swaps that economically hedge our variable rate interest. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K, for more information.
Outstanding debt and associated interest obligations of VGLNG are secured by its equity interests in the direct wholly-owned subsidiaries of VGLNG that directly or indirectly own our LNG projects. The following table summarizes our debt and associated interest obligations of VGLNG as of December 31, 2025:
Years ended December 31,
Thereafter
Total
Principal maturities (1)(2)
Interest payments (3)
Total
(1) Reflects aggregate contractual maturities for outstanding principal as of December 31, 2025. See —Funding Requirements and Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K, for more information.
(2) Excludes $3.0 billion VGLNG Series A preferred shares presented as non-controlling interest and $270 million of corresponding annual preferred dividends that are subject to adjustment and accrue indefinitely, unless optionally redeemed in accordance with their terms. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K, for more information.
(3) The interest rate for all VGLNG Senior Secured Notes is fixed. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K for more information .
There are no material differences between the financial information presented on this Form 10-K and VGLNG's financial information other than (i) certain presentational differences related to the accounting for the VGLNG Series A Preferred Shares, and (ii) stockholders’ equity of Venture Global, including the Class A common stock and any dividends payable thereon. See Item 15. —Exhibits and Financial Statement Schedules —Schedule I Financial Information of Registrant of this Form 10-K.
For further discussion of our contractual obligations as of December 31, 2025, see Item 8.— Financial Statements and Supplementary Data —Note 15 – Commitments and Contingencies of this Form 10-K for further information.
Sources and Uses of Cash
Since our inception, we have funded our operations and capital expenditures with various forms of financing, including the issuance of equity securities, project equity financings, and borrowings at VGLNG and our project entities, as well as with cash from our operations.
We expect to meet our short-term cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash, and available borrowing capacity under our existing credit
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facilities. Additionally, we expect to meet our long-term cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries.
The following table provides a summary of our cash and available borrowing capacity under existing credit facilities as of December 31, 2025:
December 31, 2025
Cash and cash equivalents
Restricted cash
Available borrowing capacity under our credit facilities (1) :
CP2 Construction Term Loan
CP2 Working Capital Facility
Plaquemines Working Capital Facility
Calcasieu Pass Working Capital Facility
Blackfin TLA Facility
Blackfin Working Capital Facility
VGLNG Revolving Credit Facility
Total available borrowing capacity under our credit facilities
Total cash and available borrowing capacity
(1) Available borrowing capacity represents total borrowing capacity less outstanding borrowings and letters of credit under each of our credit facilities as of December 31, 2025.
As of December 31, 2025, our subsidiaries had approximately $34.8 billion in outstanding debt, which consisted of $11.1 billion of debt, primarily the VGLNG Senior Secured Notes, and approximately $23.7 billion of project-level debt financing.
In addition, our project‑level subsidiary, Calcasieu Funding, issued the CP Funding Redeemable Preferred Units, which may require us to make preferential cash distributions to the holders under certain circumstances. Through August 19, 2027, no distributions of available cash are permitted from Calcasieu Funding to Venture Global or its affiliates until all accrued distributions on the CP Funding Redeemable Preferred Units have been fully settled in cash. As of December 31, 2025, the accrued distribution balance on the CP Funding Redeemable Preferred Units was $796 million. Further, on and after August 19, 2027, no distributions of available cash—beyond what is deemed necessary by management to fund VGCP's operating costs, including debt service requirements—will be permitted from Calcasieu Funding to Venture Global or its affiliates until the CP Funding Redeemable Preferred Units have been fully redeemed in cash. As of December 31, 2025, the CP Funding Redeemable Preferred Units had total redemption value and aggregate liquidation preference of $1.7 billion. For the risk factors related to our business, see Item 1.— Business and Item 1A.— Risk Factors of this Form 10-K.
We commence production at our LNG projects on a sequential basis, with each liquefaction train being brought online as it is commissioned. During the year ended December 31, 2025, the Plaquemines and Calcasieu projects generated $5.9 billion and $1.1 billion of cash flow from operations, respectively.
We believe that our current cash and cash equivalents, borrowing capacity under our existing credit facilities, and the expected proceeds from sales of LNG at our projects will provide us with sufficient liquidity for at least the next 12 months, and will enable us to fund our continuing operations, our upcoming LNG tanker milestone payments, our pipeline development projects and our expected pre-FID capital expenditures with respect to our greenfield and expansion projects.
We anticipate that we will need substantial additional debt and equity capital to commence full construction activities and achieve COD for our greenfield and expansion projects. We regularly evaluate market conditions, our capital needs, our liquidity profile, and various debt, equity and equity-linked financing alternatives at Venture Global, VGLNG, our project entities, and other subsidiaries, for opportunities to raise additional debt or equity capital and to support our growth and enhance our capital structure. The availability, timing and terms of any such
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additional debt and equity financing will depend on various factors, including market conditions at the time. To the extent we issue equity or equity-linked securities, there can be no assurance that any such funding will not be expensive or dilutive to stockholders.
If we are unable to obtain additional funding on a timely basis or on terms that are acceptable to us, we will have to delay, scale back or eliminate construction plans for our greenfield and expansion projects, any of which could harm our business, financial condition and results of operations. Any delays in construction could prevent us from commencing operations when we anticipate and would prevent us from realizing anticipated cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to our incurrence of construction costs and other outflows as well as the timing of our receipt of cash flows under export contracts in relation to our incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between our liquidity sources and cash needs, including factors such as construction delays and breaches of construction agreements by our contractors. After the construction period, our business may not generate sufficient cash flow from operations, currently anticipated costs may increase or future borrowings may not be available to us in amounts sufficient to enable us to pay our indebtedness or to fund our other liquidity needs, including operating expenses. See Item 1A.— Risk Factors of this Form 10-K.
Material Financings
Venture Global IPO
In January 2025, we closed our IPO in which we issued and sold 70 million shares of Class A common stock. Our shares of Class A common stock were sold at an initial public offering price of $25.00 per share, which generated net proceeds of approximately $1.7 billion after deducting underwriting discounts and commissions of $70 million and approximately $10 million of offering expenses. See additional discussion in Item 8. — Financial Statements and Supplementary Data —Note 16 – Equity of this Form 10-K for further information.
VGLNG Debt and Equity Financing
VGLNG Senior Secured Notes. In May 2023, VGLNG issued $2.25 billion aggregate principal amount of 8.125% Senior Secured Notes due 2028, or the VGLNG 2028 Notes, and $2.25 billion aggregate principal amount of 8.375% Senior Secured Notes due 2031, or the VGLNG 2031 Notes. The VGLNG 2028 Notes bear interest at a rate of 8.125% per annum and mature on June 1, 2028. The VGLNG 2031 Notes bear interest at a rate of 8.375% per annum and mature on June 1, 2031. The interest on each such series of notes is payable semi-annually in arrears on each June 1 and December 1.
In October 2023, VGLNG issued $2.5 billion aggregate principal amount of 9.500% Senior Secured Notes due 2029, or the VGLNG 2029 Notes, and $1.5 billion aggregate principal amount of 9.875% Senior Secured Notes due 2032, or the VGLNG 2032 Notes. In addition, in November 2023, VGLNG issued an additional $500 million aggregate principal amount of VGLNG 2029 Notes, and an additional $500 million aggregate principal amount of VGLNG 2032 Notes. The VGLNG 2029 Notes bear interest at a rate of 9.500% per annum and mature on February 1, 2029. The VGLNG 2032 Notes bear interest at 9.875% per annum and mature on February 1, 2032. The interest on each such series of notes is payable semi-annually in arrears on each February 1 and August 1, commencing on August 1, 2024.
In July 2024, VGLNG issued $1.5 billion aggregate principal amount of 7.000% Senior Secured Notes due 2030, or the VGLNG 2030 Notes. The VGLNG 2030 Notes bear interest at a rate of 7.000% per annum and mature on January 15, 2030. The interest on each such series of notes is payable semi-annually in arrears on each January 15 and July 15, commencing on January 15, 2025.
The VGLNG 2028 Notes, the VGLNG 2029 Notes, the VGLNG 2031 Notes, the VGLNG 2032 Notes and the VGLNG 2030 Notes are secured by first-priority liens in, subject to permitted liens and certain other exceptions, substantially all of our existing and future assets, if any, including our direct wholly-owned subsidiaries that directly
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or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, or any related pipeline.
VGLNG Series A Preferred Shares. In September 2024, VGLNG issued three million shares of 9.000% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share, or the VGLNG Series A Preferred Shares, for aggregate gross proceeds of $3.0 billion. The VGLNG Series A Preferred Shares are not convertible into any other securities and have limited voting rights. Cumulative cash dividends on the VGLNG Series A Preferred Shares are payable semi-annually, in arrears, on each March 30 and September 30, when, as and if declared by the board of directors of VGLNG.
VGLNG Revolving Credit Facility. On November 7, 2025, VGLNG entered into the $2.0 billion senior secured revolving credit VGLNG Revolving Credit Facility. Borrowings under the VGLNG Revolving Credit Facility bears interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loan is 2.500% and the set margin rate for base rate loan is 1.500%. The Company also incurs commitment fees of 0.350% of the undrawn available commitments of the VGLNG facility. Proceeds from the VGLNG Revolving Credit Facility can be used for general corporate purposes of VGLNG and its subsidiaries. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt and Item 8. — Financial Statements and Supplementary Data —Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.
Project Debt and Equity Financing
Calcasieu Project. In August 2019, our subsidiary, VGCP, obtained $5.8 billion in project financing consisting of an approximately $5.5 billion senior secured construction term loan, or the Calcasieu Pass Construction Term Loan, and a $300 million senior secured working capital facility, or the Calcasieu Pass Working Capital Facility, or collectively, the Calcasieu Pass Credit Facilities, that mature on August 19, 2026 and bear interest at SOFR plus an applicable margin, payable monthly in arrears. The proceeds from the Calcasieu Pass Credit Facilities were used to fund the costs of developing, constructing and commissioning the Calcasieu Project. In September 2021, VGCP upsized the Calcasieu Pass Working Capital Facility by an incremental $255 million to $555 million. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt and Item 8. — Financial Statements and Supplementary Data —Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.
In May 2019, our subsidiaries, Calcasieu Funding and Calcasieu Holdings, entered into two unit purchase agreements with certain funds associated with Stonepeak Infrastructure Partners, pursuant to which Calcasieu Funding and Calcasieu Holdings issued 9 million and 4 million preferred units, respectively, for $1.3 billion of total gross proceeds at a face value of $100 per preferred unit. These transactions closed in August 2019 and proceeds were used to fund the equity portion of the cost of developing, constructing and commissioning the Calcasieu Project. Upon COD of the Calcasieu Project in April 2025, the CP Holdings Convertible Preferred Units converted into Class B common units, representing a 23% ownership interest in the Calcasieu Project. See Item 8. — Financial Statements and Supplementary Data —Note 17 – Redeemable Stock of Subsidiary and Item 8. — Financial Statements and Supplementary Data —Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.
In August 2021, VGCP issued $2.5 billion aggregate principal amount of senior secured notes, consisting of $1.25 billion of senior secured notes due 2029, or the VGCP 2029 Notes, and $1.25 billion of senior secured notes due 2031, or the VGCP 2031 Notes. The VGCP 2029 Notes bear interest at a rate of 3.875% per annum and the VGCP 2031 Notes bear interest at a rate of 4.125% per annum, with each series of notes payable semi-annually in arrears on February 15 and August 15 of each year. The VGCP 2029 Notes will mature on August 15, 2029 and the VGCP 2031 Notes will mature on August 15, 2031. In November 2021, VGCP issued $1.25 billion aggregate principal amount of senior secured notes due 2033, or the VGCP 2033 Notes. The VGCP 2033 Notes bear interest at a rate of 3.875% per annum, payable semi-annually in arrears on May 1 and November 1 of each year. The VGCP 2033 Notes will mature on November 1, 2033. In January 2023, VGCP issued $1.0 billion aggregate principal amount of senior secured notes due 2030, or the VGCP 2030 Notes, and together with the VGCP 2029 Notes, the VGCP 2031 Notes and the VGCP 2033 Notes, the VGCP Senior Secured Notes. The VGCP 2030 Notes bear interest at a rate of 6.250% per annum, payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2023. The VGCP 2030 Notes will mature on January 15, 2030. The aggregate proceeds
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from these issuances were used to prepay $4.2 billion outstanding under the Calcasieu Pass Credit Facilities. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K for further discussion.
Plaquemines Project. In May 2022, our subsidiary, VGPL, obtained approximately $9.6 billion in project financing consisting of an approximately $8.5 billion term loan facility, or the Plaquemines Construction Term Loan, and a $1.1 billion working capital revolving facility, or the Plaquemines Working Capital Facility, or collectively, the Plaquemines Credit Facilities, that matures in May 2029, to fund the development and construction of Phase 1 of the Plaquemines Project. The project financing facilities were upsized in March 2023 to fund the development and construction of Phase 2 of the Plaquemines Project. In the aggregate, the upsized Plaquemines Credit Facilities, are comprised of an approximately $12.9 billion Plaquemines Construction Term Loan and a $2.1 billion Plaquemines Working Capital Facility, that mature on May 25, 2029 and bear interest at SOFR plus an applicable margin, payable monthly in arrears. In connection with the upsize, PL Holdings entered into the Plaquemines Equity Bridge Facility, an approximately $1.7 billion secured credit facility equity bridge credit facility to fund a portion of project costs for the Plaquemines Project. In July 2024, we prepaid the remaining outstanding amount of the Plaquemines Equity Bridge Facility in full using proceeds from the VGLNG 2030 Notes. The net proceeds from the project financing arrangements will be used be used to fund the costs of financing, developing, constructing, and commissioning the Plaquemines Project. See Item 8. — Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K for further discussion.
In April 2025, our subsidiary, VGPL issued $2.5 billion aggregate principal amount of senior secured notes, consisting of $1.25 billion of senior secured notes due 2033, or the VGPL 2033 notes, and $1.25 billion of senior secured notes due 2035, or the VGPL 2035 notes. The VGPL 2033 notes bear interest at a rate of 7.500% per annum and the VGPL 2035 notes bear interest at a rate of 7.750% per annum, with interest on each series of notes payable semi-annually in arrears on May 1 and November 1 of each year. The VGPL 2033 notes will mature on May 1, 2033 and the VGPL 2035 notes will mature on May 1, 2035. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $2.7 billion outstanding under the Plaquemines Construction Term Loan.
In July 2025, VGPL issued $4.0 billion aggregate principal amount of senior secured notes, consisting of $2.0 billion of senior secured notes due 2034, or the VGPL 2034 notes, and $2.0 billion of senior secured notes due 2036, or the VGPL 2036 notes. The VGPL 2034 notes bear interest at a rate of 6.500% per annum and the VGPL 2036 notes bear interest at a rate of 6.750% per annum, with interest on each series of notes payable semi-annually in arrears on January 15 and July 15 of each year. The VGPL 2034 notes will mature on January 15, 2034 and the VGPL 2036 notes will mature on January 15, 2036. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $4.5 billion outstanding under the Plaquemines Construction Term Loan.
In December 2025, VGPL issued $3.0 billion aggregate principal amount of senior secured notes, consisting of $1.75 billion of senior secured notes due 2030 or the VGPL 2030 notes, and a $1.25 billion of senior secured notes due 2034 or the VGPL 2034. The VGPL 2030 notes bear interest at a rate of 6.125% per annum and the VGPL 2034 notes bear interest at a rate of 6.500% per annum, with interest on each series of notes payable semi-annually in arrears on June 15 and December 15 of each year. The VGPL 2030 notes will mature on December 15, 2030 and the VGPL 2034 notes will mature on June 15, 2034. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $3.2 billion outstanding under the Plaquemines Construction Term Loan.
CP2 Project. In May 2025, our subsidiary, CP2, entered into the CP2 Bridge Facilities, a $3.0 billion secured credit facility to fund a portion of the project costs for the CP2 Project prior to the closing of the full project financing for Phase 1 of the CP2 Project. Borrowings under the CP2 Bridge Facilities bear interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loans is 3.500% and the set margin rate for base rate loans is 2.500%. The Company also incurred commitment fees on the undrawn available commitments of the CP2 Bridge Facilities.
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In July 2025, Phase 1 of the CP2 Project achieved FID and we obtained $15.1 billion in project financing to fund the development and construction of Phase 1 of the CP2 Project. CP2 Holdings entered into the $3.0 billion secured CP2 Holdings EBL Facilities, due July 28, 2028. Borrowings under the CP2 Holdings EBL Facilities bear interest at a set margin rate over the debt term plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loans is 3.500% and the set margin rate for base rate loans is 2.500%. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter. CP2, as borrower, and CP2 Procurement and CP Express, as guarantors, entered into the $12.1 billion senior secured CP2 Credit Facilities, due July 28, 2032. Borrowings under the CP2 Credit Facilities bear interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for the SOFR-based loans ranges from 2.250% to 2.750% and the set margin rate for the base rate loans ranges from 1.250% to 1.750%. The Company also incurs commitment fees from 0.788% to 0.963% of the undrawn available commitments of the CP2 Working Capital Facility. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter.
A portion of the proceeds from the project financing was used to prepay the outstanding CP2 Bridge Facilities in full and pay costs incurred in connection with the project financing. The remaining proceeds from the project financing will be used to fund the costs of financing, developing, constructing, and placing in service Phase 1 of the CP2 Project.
Pipeline infrastructure projects. In September 2025, our subsidiary, Blackfin, entered into the $1.6 billion senior secured Blackfin Credit Facilities. Under the Blackfin Credit Facilities, the Blackfin TLA Facility and Blackfin Working Capital Facility are due September 29, 2030 and the Blackfin TLB Facility is due September 29, 2032 . Borrowings under the Blackfin TLA Facility and Blackfin TLB Facility bear interest at a set margin over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for the Blackfin TLA Facility for SOFR-based loans is 2.250% and the set margin rate for base rate loans is 1.250%, subject to future increases. The set margin rate for the Blackfin TLB Facility for SOFR-based loans is 3.000% and the set margin rate for base rate loans is 2.000%. The Company also incurs commitment fees from 0.438% to 0.875% of the undrawn available commitments under the Blackfin TLA Facility and Blackfin Working Capital Facility. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter.
Proceeds from the Blackfin Credit Facilities were used to reimburse $889 million to VGLNG for prior expenditures related to the development and construction of the Blackfin Pipeline, and pay certain costs incurred in connection with the project financing. The remaining proceeds will be used to fund a portion of the costs to develop, construct and manage the Blackfin Pipeline.
See Item 8.— Financial Statements and Supplementary Data —Note 11 – Debt of this Form 10-K for additional discussion of material financing activity.
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Cash Flows
Year ended December 31, 2025 compared to year ended December 31, 2024
The following table shows a summary of our consolidated cash flows for the periods indicated:
Years ended December 31,
Change
Net cash from operating activities
Net cash used by investing activities
Net cash from financing activities
Operating activities
Net cash from operating activities for the year ended December 31, 2025 was $6.6 billion, a $4.4 billion, or 206%, increase from $2.1 billion for the year ended December 31, 2024.
Change in cash from operating activities (in billions)
• The increase in cash received from LNG sales was due to $9.3 billion of higher cash receipts primarily at Plaquemines from increased LNG sales volumes, partially offset by $0.9 billion lower cash receipts at Calcasieu from lower LNG sales prices.
• The increase in cash paid for feed gas was due to $3.2 billion of higher payments at Plaquemines from increased LNG sales volumes and $696 million at Calcasieu from higher costs for feed gas; and
• The increase in cash received for the settlement of derivatives was primarily due to $1.1 billion of proceeds from the pro rata settlement of a portion of the interest rate swaps associated with the Plaquemines Credit Facilities in 2025, with no similar settlements in 2024.
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Investing activities
Net cash used by investing activities for the year ended December 31, 2025 was $13.2 billion, a $0.9 billion, or 7%, decrease from $14.2 billion for the year ended December 31, 2024. The decrease in net cash outflows was primarily due to:
Change in cash used by investing activities (in billions)
• The decrease of $352 million of cash paid for capital expenditures comprised of the following:
Years ended December 31,
Change
Plaquemines Project
CP2 Project
Pipeline projects
LNG tankers
Calcasieu Project
VGLNG capitalized interest
Other
Total
• The decrease of $500 million of other investing cash outflows was comprised of the following:
◦ a decrease of $298 million due to cash outflows from investments in interest bearing deposits during the year ended December 31, 2024 as compared to cash inflows from the redemption of certificates of deposit during the year ended December 31, 2025; partially offset by
◦ an increase of $132 million due to cash inflows from Test LNG proceeds during the year ended December 31, 2025, with no similar inflow during the year ended December 31, 2024.
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Financing activities
Net cash from financing activities for the year ended December 31, 2025 was $5.5 billion, a $5.3 billion, or 49%, decrease from $10.8 billion for the year ended December 31, 2024. The decrease in net cash inflows was primarily due to:
Change in cash from financing activities (in billions)
• The change in the issuance and repayment of debt is primarily comprised of the following:
Years ended December 31,
Change
Issuance of debt and draws on Credit Facilities
Plaquemines Project
CP2 Project
Pipeline projects
VGLNG
Other
Total issuance of debt
Repayment of debt
Plaquemines Project
CP2 Project
Calcasieu Project
Total repayment of debt
Total change in issuance and repayments of debt, net
• The change in the proceeds from the issuance of Class A Common Stock of $1.8 billion is due to our IPO during the during the year ended December 31, 2025, with no similar activity during the same period in 2024; and
• The change in the issuance of the VGLNG Series A Preferred Shares of $3.0 billion during the year ended December 31, 2024, with no similar activity during the same period in 2025.
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Key Trends and Uncertainties
Management expects several factors to influence our operations, financial condition and cash flows in 2026 and beyond. While proceeds generated from the sale of LNG produced by our Calcasieu and Plaquemines projects may offset certain near-term uncertainties, events that arise or evolve differently from current assumptions could materially affect our results. We continue to monitor these developments and respond as conditions warrant. For additional discussion, see Item 1.— Business and Item 1A.— Risk Factors of this Form 10-K.
Macroeconomic
Global economic volatility may heighten risks related to tariffs, labor availability, capital market access, exchange rate and interest rate fluctuations, and market balance and margins.
Tariffs and trade policy — The global trade environment remains fluid. United States and foreign tariff actions, including potential retaliatory measures, may lead to higher equipment and material costs for our construction projects and affect LNG demand or pricing in affected markets. We rely on significant equipment imported from the European Union, or EU, and any deterioration in trade relations or new duties could increase project costs and reduce competitiveness. The potential cost impact is currently expected to be concentrated in our CP2 Project. The impact of tariffs effective as of December 31, 2025 has been incorporated into our current budget for the CP2 Project. The cumulative impact of all new tariffs implemented in 2025 increased our total expected capital costs by approximate ly $600 million . Because the Plaquemines Project has already procured substantially all critical equipment, tariff-related effects are expected to be immaterial for that project. Future projects and expansions may also be subject to higher costs depending on the timing and scope of procurement activities; our project budgets for these initiatives also reflect our best estimates of tariffs at the currently enacted rates. This assessment does not reflect the impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on applicable tariff rates and global trade. The impact of this ruling, and the federal government's response, are unknown and could alter our estimated capital project costs. Global economic uncertainty and any related reduction in economic activity or capital investment as a result of tariffs and any retaliatory actions from other countries could have a material impact on our financial condition, results of operations and/or cash flows through reduced demand and competitiveness for both our long-term and short-term contract sales in countries that may be affected by those policies. The Company continues to monitor this situation.
Labor market — Competition for skilled labor along the Gulf Coast remains intense. Persistentshortages in highly skilled construction labor—driven by concurrent LNG construction and major infrastructure and datacenter development—may amplify wage pressure, recruitment and retention difficulty. Sustained tightness in the labor pool could raise project costs or extend construction timelines. This could materially increase our estimated project costs, which include significant labor costs, and could have a material impact on our financial condition, results of operations and/or cash flows.
Capital markets and interest rates — Capital markets have experienced recent volatility and liquidity constraints due to uncertainty around the global economic impact of tariffs, inflation and monetary policy. Although the annual rate of inflation has moderated, future changes in interest rate policy could reignite inflationary pressures or increase the overall cost of capital. Such volatility may adversely impact access to the market for corporate or project lending or lead to higher borrowing costs. We aim to mitigate our exposure to interest rate volatility through interest rate swaps, but we will not be able to mitigate all interest rate risk. Additionally, we may sometimes prioritize access to capital or capital recycling over interest rates when determining when to access capital markets.
Market Balance and Margins — Following a period of strong global LNG demand from 2022 to 2025, the market is transitioning to a period of increased supply and normalized shipping conditions. Additionally, higher Henry Hub natural gas prices, elevated feed gas transportation (including costs to supply feed gas to less liquid delivery locations, or basis differentials), and marine freight costs could compress our operating margins if the spread between total delivered costs and the prices at which we sell LNG narrows. This margin pressure is currently
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most evident for sales indexed to the TTF benchmark, which has remained comparatively stable over recent periods even as feed gas (largely linked to Henry Hub) and shipping costs have increased. For example, beginning in late 2025 and into early 2026, Henry Hub prices rose sharply and basis differentials (at our Plaquemines Project) intensified, while TTF indices remained steady, narrowing price spreads on certain cargos. If these market conditions persist, our margins on spot and short-term sales could be reduced, and together with continued cost inflation or sustained high feed gas and freight prices, could adversely affect our cash flows and project returns. Our long-term contract portfolio and low-cost production model are expected to mitigate some of these impacts, but prolonged margin pressure could have a material impact on our financial condition, results of operations and/or cash flows.
Geopolitical
Evolving global political and energy-policy conditions continue to shape LNG demand and pricing. In January 2026, the EU voted a plan into law to phase out Russian-sourced gas and LNG by 2027. The ban is expected to create a lasting increase in demand for non-Russian LNG imports, including U.S. supply. While supportive of long-term growth, the transition may create short-term uncertainty in market pricing. Elsewhere, geopolitical developments in Venezuela—including fluctuations in sanctions policy and potential shifts in regional oil and gas production—may influence global supply balances, energy pricing and investment flows across the Americas. Broader uncertainty from conflicts in major energy-producing regions like the Middle East, selective sourcing decisions in Asia, and international trade realignments could also affect contract timing, volumes and average realized prices. We continue to monitor these developments and assess potential implications on our financial condition, results of operations and/or cash flows.
Regulatory
Recent U.S. policy actions have generally supported continued LNG development, including the DOE's resumption of Non-FTA Nation export authorizations and final approvals for our CP2 Project. While these trends are favorable, they remain subject to change. These actions have resulted in increased opportunities to continue development of our projects, including our expansion projects. While we cannot predict whether these trends will continue or whether our applications, approvals or permits will attract significant opposition in the permitting processes, we intend to continue to progress our projects through the various permitting and regulatory channels over their expected timelines. Any future significant changes in this trend could have a material impact on our financial condition, results of operations and/or cash flows.
Post-COD SPAs
The Calcasieu Project is involved in disputes and arbitration proceedings with its post-COD SPA customers. Such customers are asserting, among other claims, that the Calcasieu Project was delayed in achieving COD under its post-COD SPAs. Following the positive resolution of three arbitration proceedings, the Calcasieu Project remains involved in arbitration proceedings with four of its post-COD SPA customers.
We were notified in October 2025 that a partial final award had been issued in the arbitration proceedings with BP. The award issued by the arbitration tribunal found that the VGCP had breached its obligations to declare COD of the Calcasieu Project in a timely manner and act as a “Reasonable and Prudent Operator” pursuant to the BP post-COD SPA, along with certain other obligations. Remedies were not addressed in the partial final award and will be determined in a separate damages hearing which has not been scheduled but is anticipated to occur in 2026 or 2027. A final award is expected to be issued following the damages portion of the hearing. Based on the terms of the award, the Company does not anticipate that the final award will be subject to the seller aggregate liability limitation in the BP post-COD SPA. The remedies sought by BP include damages ranging from $3.7 billion to potentially in excess of $6.0 billion, as well as interest, costs and attorneys’ fees. We believe BP’s theory and calculations of damages are without merit and that the magnitude of damages sought by BP is not recoverable under the express terms of the post-COD SPA, which include express limits on the tribunal’s jurisdictional authority, although there can be no assurance as to the outcome of the damages portion of the hearing.
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The remedies sought by the other three Calcasieu Project post-COD customers in arbitration proceedings include damages ranging between $3.4 billion and $4.1 billion in the aggregate, rather than the termination of the post-COD SPA. We believe these three disputes are subject to the relevant seller aggregate liability limitation under the applicable post-COD SPA, which amount to $595 million in the aggregate. However, these customers are also disputing whether the liability limitations in such post-COD SPAs are applicable, and therefore are claimingdamages in excess of the liability limitations.
If these disputes are not resolved favorably, adverse outcomes could require substantial payments that exceed our liability accruals or the relevant limits under the post-COD SPAs. Such payments could negatively affect project-level cash flows, restrict distributions to the Company or cause acceleration of related debt under project-financing agreements. The Company's best estimate of potential financial impacts of these disputes are currently reflected in our financial statements and disclosures.
For further discussion, see Item 1A.— Risk Factors — Risks Relating to Regulation and Litigation — If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock , Note 4 – Revenue from Contracts with Customers in Item 8.— Financial Statements and Supplementary Data of this Form 10-K, and Part I Item 3.— Legal Proceedings of this Form 10-K.
Critical Accounting Policies and Estimates
Use of Estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. We evaluate our assumptions on an ongoing basis. The accounting policies and estimates discussed below are considered by our management to be critical to an understanding of our financial statements as their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. While we believe the estimates used in the preparation of the consolidated financial statements are appropriate, actual results could differ from these estimates.
Revenue from Contracts with Customers
The transaction price defined in our contracts for the sale of LNG to third-party customers includes both fixed and variable components including variable consideration for contingent payments for non-performance, delays, or other damages, which may be due from the Company and could result in the significant reversal of revenue. Any estimates for contingent payments are recognized as a reduction to the transaction price until the future significant reversal of revenue is no longer probable of occurring or once the uncertainty is resolved. For further discussion, see Item 8. — Financial Statements and Supplementary Data —Note 4 – Revenue from Contracts with Customers of this Form 10-K, for more information.
Critical Accounting Policies
Revenue Recognition
The majority of our nameplate capacity produced at our projects after COD will be sold under long-term 20-year Contracted SPAs. We aim to market and sell the expected nameplate capacity at our subsequent projects under a combination of long-term 20-year SPAs as well as short- and medium-term contracts to optimize the average fixed liquefaction fee across our SPAs. Delivery under post-COD SPAs commences upon achieving COD of the respective LNG facilities, which has only occurred for our Calcasieu Project. Delivery under our Firm-start SPAs commences upon a contractually defined date. LNG produced during the commissioning phase prior to an LNG
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facility achieving COD is sold to various customers under master SPAs, either as single cargo or as multiple cargos to be loaded over a period of time, and are based on spot and/or forward prices at the time of execution.
We recognize revenue when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. Revenue from the sale of LNG is recognized at the point in time when the LNG is delivered to the customer at the agreed upon LNG terminal which is the point when legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each molecule of LNG is viewed as a separate performance obligation. Under our projects' LNG sales agreements, LNG may be transferred to the customer on delivery terms including FOB, DPU or DES. When LNG is sold on terms other than FOB, transportation costs incurred by us are considered to be fulfillment costs and are not separate performance obligations within the arrangement. The majority of the Company's post-COD SPAs are sold FOB. The stated contract price, including both fixed and variable components, is representative of the stand-alone selling price for LNG at the time the contract was negotiated. The Company's LNG sales agreements include provisions for contingent payments for non-performance, delays, or other damages, which may be due from the Company, and represent variable consideration. Any estimates for contingent payments are based on either the Company's best estimate of the most likely outcome or the expected value, depending on which method best predicts the total net consideration to which the Company will be entitled over the term of the LNG sales agreement. Payments, and estimates for contingent payments, made by the Company are recognized as a reduction to the transaction price (as an adjustment to the fixed liquefaction fee) as LNG is delivered to customers over the term of the LNG sales agreement. Payment terms are within 30 days after the LNG is delivered.
Proceeds from the sale of test LNG generated during the early commissioning of an LNG project are determined based on estimates of LNG production generated from commissioning activities and recognized as a reduction to the cost basis of construction in progress until assets are placed in service in accordance with the accounting guidance.
Capitalization of Development and Construction Costs
Generally, the costs incurred to develop our projects are treated as development expenses until management concludes that construction and completion of the relevant project is considered probable. Costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our projects. In assessing probability, we consider whether: (i) management has committed to funding construction of the project, (ii) financing for the project is available and (iii) the ability exists to meet the necessary local and other governmental regulations. Certain costs are capitalized prior to a project meeting the criteria otherwise necessary for capitalization, which requires judgment and is based upon our assessment of our ability to realize the future benefits associated with these assets. For example, we have capitalized the cost of equipment and materials that are expected to be used on projects that are not yet probable when the equipment and materials have alternative use and are otherwise recoverable in other projects or for resale. Our construction and equipment supplier arrangements also contain various terms including retainage, performance bonuses, and liquidateddamages, that impact the amount and timing of the recognition of the related costs. For further discussion, see Item 8. — Financial Statements and Supplementary Data —Note 6 – Property, Plant and Equipment of this Form 10-K, for more information.
Derivative Instruments
We reflect all contracts that meet the definition of a derivative, except those designated and qualifying as NPNS as either assets or liabilities on the consolidated balance sheets at fair value. Changes in the fair value of derivative instruments are recognized in earnings, unless we elect to apply hedge accounting and meet the specified criteria in ASC 815, Derivatives and Hedging. We designate derivatives instruments as cash flow hedges based on all available facts and circumstances.
We enter into interest rate swap agreements to mitigate volatility arising from changes in interest rates. We do not utilize derivatives for trading or speculative purposes. Derivative instruments are recognized at their fair values on the consolidated balance sheets. Changes in fair value of derivative instruments designated as cash flow hedges are recognized in accumulated other comprehensive income or loss, or AOCL, until the hedged transaction affects
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earnings, at which time the deferred gains and losses are reclassified to earnings. Cash flows of our derivatives which are not designated as hedging relationships are classified as operating activities in the consolidated statements of cash flows unless the derivatives contain an other-than-insignificant financing element at inception, in which case the associated cash flows are classified as financing activities. Derivative assets and liabilities are presented net on the consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.
We discontinue hedge accounting on a prospective basis if the derivative is no longer expected to be highly effective as a hedge, if the hedged transaction is no longer probable of occurring, or if we de-designate the instrument as a cash flow hedge. Any gain or loss in AOCL at the time of de-designation is reclassified into earnings in the same period the hedged transaction affects earnings unless the underlying hedged transaction is probable of not occurring, in which case, any gain or loss in AOCL is reclassified into earnings immediately. For further discussion, see Item 8.— Financial Statements and Supplementary Data —Note 12 – Derivatives of this Form 10-K for more information.
Income Taxes
We account for U.S. federal, state and foreign income taxes under the asset and liability method, which requires the recognition of deferred income tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine income tax assets and liabilities based on the differences between the financial statement and income tax basis for assets and liabilities using the enacted statutory tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date.
A valuation allowance is provided for deferred income taxes if it is more-likely-than-not these items will either expire before we are able to realize their benefits or if future deductibility is uncertain. Additionally, we evaluate tax positions under a more-likely-than-not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting.
Our accounting policy for releasing the income tax effects from AOCL occurs on a portfolio basis. For further discussion, see Item 8. — Financial Statements and Supplementary Data —Note 14 – Income Taxes of this Form 10-K for more information.
