Venture Global, Inc.

Previous wording

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.

Current wording

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.

Previous wording

Plaquemines Project. In December 2024, we first produced LNG from our second LNG export facility, and as of December 31, 2024, we exported one cargo from the Plaquemines Project, which was in-transit to our customer. In December 2024, a portion of the facility’s assets, representing $11.4 billion of costs, were placed in service in accordance with GAAP. As of December 31, 2024, physical construction of the Plaquemines Project was ongoing and the project’s commissioning program remained underway. In 2024, we incurred $9.3 billion of project costs, the majority of which were capitalized.

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

Sales of LNG during commissioning of our projects. We aim to generate cash proceeds from the sale of LNG produced during the commissioning phase of each of our projects. Our ability to generate such cash proceeds, and the amount of any such cash proceeds, will depend primarily on the duration of the commissioning phase for each of our projects, the volume of LNG that we are able to produce during the commissioning phase, our ability to negotiate sales of LNG produced during the commissioning phase, as well as the market price for LNG at the time of such sales. As a result, the amount of cash proceeds we are able to generate from such sales of commissioning cargos will likely differ from period to period and from project to project, and such differences could be material.

Current wording

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.

Previous wording

Sales of LNG post-COD of our projects. We aim to generate cash proceeds from the sale of LNG produced after COD for each of our projects under a combination of long-term 20-year post-COD SPAs as well as short- and medium-term post-COD SPAs to optimize the average fixed facility charge across our SPAs. Further, to the extent our projects generate excess capacity relative to the nameplate capacity, we expect to sell such excess capacity as described below. None of our projects have achieved COD as of the date of this Form 10-K. Our ability to generate cash proceeds from such sales, and the amount of any such 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 following key factors:

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

Project costs and expenses. We currently have five projects in various stages of development. We expect our development, construction and commissioning expenses for any particular project to increase significantly as we approach and commence the construction phase, and we expect these expenses will continue to be significant until the commissioning phase has been completed and the relevant project reaches its COD. Moreover, our project costs may be higher than we currently estimate due to many factors outside of our control, which could lead to higher development, construction and commissioning expenses for our projects. In addition, we expect to increase our project‑dedicated staff as we progress towards the commencement of construction of the CP2 Project, the CP3 Project and the Delta Project and when we subsequently commence operation at our facilities. As a result, we anticipate that operating and maintenance expenses will increase significantly as we approach commissioning and operation of our projects (as was the case for the Calcasieu Project). We outsource certain major equipment maintenance activities under long-terms service arrangements, but our various operating subsidiaries are responsible for performing day-to-day operations and maintenance work for our projects. See Item 1.—Business—Major Consultants and Contractors of this Form 10-K for more information. Once one of our projects has commenced full commercial operations, we anticipate that the timing of the operating and maintenance costs under the long-term service arrangements for that project will be relatively predictable, subject to inflation, and will generally increase during periods in which regularly scheduled or other maintenance is performed. 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.

Current wording

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.

Previous wording

Effective tax rates and regulations. We utilize various tax incentive programs the State of Louisiana offers, 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 the CP3 Project and the Delta Project, 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.

Current wording

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.

Previous wording

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 the post-COD SPAs that include a fixed facility charge and that we enter into will only be partially adjusted for inflation over the contract term, as is the case with our existing post-COD SPAs as described above. In addition, we anticipate that our operating costs will experience inflationary pressure over time, and the commodity charge we charge our customers for recovery of these costs is based on the price of natural gas per MMBtu. 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 1 A.—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 usof this Form 10-K.

Current wording

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 usof this Form 10-K.

Previous wording

Seasonality. Seasonal weather can affect demand for LNG and accordingly can impact our ability to sell LNG during the commissioning of our facilities or once our facilities achieve their respective CODs. We have already begun experiencing, and we expect to experience for our other projects, 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. 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, 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.

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

This increase was primarily due to:

Current wording

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.

Previous wording

Operating and maintenance expense was $391 million for the year ended December 31, 2023, a $251 million, or 179%, increase from $140 million during the year ended December 31, 2022. This increase was primarily due to higher operating costs at the Calcasieu Project to support ongoing commissioning and remediation work, personnel costs, and insurance, and higher operating costs in support of the Plaquemines Project primarily due to an increase in non-capitalizable personnel costs and ARO accretion.

Current wording

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.

Previous wording

General and administrative expense was $312 million for the year ended December 31, 2024, a $88 million, or 39%, increase from $224 million during the year ended December 31, 2023. This increase was primarily due to higher personnel costs of $43 million due to an increase in employee headcount, increases in promotional activities of $10 million, and increases in external services of $6 million.

Current wording

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.

Previous wording

Development expense was $490 million for the year ended December 31, 2023, a $179 million, or 58%, increase from $311 million during the year ended December 31, 2022. This increase was primarily due to an increase in early development activities and personnel costs related to the CP2 Project, partially offset by the Plaquemines Project being deemed probable in March 2022, and the majority of the costs to develop the facility subsequently being capitalized.

Current wording

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.

Previous wording

Interest income was $244 million during the year ended December 31, 2024, a $72 million, or 42%, increase from $172 million during the year ended December 31, 2023. This increase was primarily due to higher average cash balances and interest rates during the year ended December 31, 2024, compared to the same period in 2023.

Current wording

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.

Previous wording

Loss on financing transactions was $14 million for the year ended December 31, 2024, a $109 million, or 89%, decrease from $123 million during the year ended December 31, 2023. This decrease was primarily due 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, as compared to the write-off of debt issuance costs associated with the prepayment of a term loan at VGLNG, and the partial prepayments of both the Plaquemines Equity Bridge Facility and the Calcasieu Pass Credit Facilities during the year ended December 31, 2023.

Current wording

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.

Previous wording

Income tax expense was $437 million for the year ended December 31, 2024, a $379 million, or 46%, decrease from $816 million during the year ended December 31, 2023, primarily driven by a decrease in pre-tax income. Our effective tax rate was 20.0% for the year ended December 31, 2024, as compared to 18.4% for the year ended December 31, 2023. The 2024 effective tax rate was lower than the statutory income tax rate due to a combination of factors including, research and development tax credits, guaranteed payments to non-controlling interests, and non-deductible expenses.

Current wording

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.

Previous wording

Net income was $1.7 billion for the year ended December 31, 2024, a $1.9 billion, or 52%, decrease from $3.6 billion during the year ended December 31, 2023. This decrease was primarily the result of a decrease in income from operations due to lower revenue earned from the sale of LNG, partially offset by lower cost of sales, partially offset by an increase in gain on derivatives and a decrease in income tax expense, as discussed above.

Current wording

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.

Previous wording

Net income attributable to redeemable stock of subsidiary was $144 million for the year ended December 31, 2024, a $14 million, or 11%, increase from $130 million during the year ended December 31, 2023. This increase was from 2024 paid-in-kind distributions on the Redeemable Preferred Units.

Current wording

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.

Previous wording

Dividends on VGLNG Series A Preferred Shares were $68 million for the year ended December 31, 2024. This increase was due to the September 2024 issuance of the VGLNG Series A Preferred Shares and the corresponding accumulated but undeclared dividends. There was no similar activity during the year ended December 31, 2023.

Current wording

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.

Previous wording

Net income attributable to common stockholders was $1.5 billion for the year ended December 31, 2024, a $1.2 billion, or 45%, decrease from $2.7 billion during the year ended December 31, 2023. This decrease was primarily resulting from the changes discussed above.

Current wording

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.

Previous wording

We have three reportable segments, which consist of the Calcasieu Project, the Plaquemines Project, and the CP2 Project. Each reportable segment includes activity of both the respective liquefaction and export terminal and the associated pipeline facilities that will supply the natural gas to that export terminal. Activities relating to certain development stage projects and our shipping business, overhead costs not directly associated with our LNG projects (for example, general and administrative and marketing expenses) and inter-segment eliminations are not material and therefore are included in corporate, other and eliminations. Our segment performance is evaluated based on income (loss) from operations.

Current wording

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.

Previous wording

During the year ended December 31, 2024, the Calcasieu Project had income from operations of $2.8 billion, a $2.8 billion, or 50%, decrease from $5.6 billion during the year ended December 31, 2023.

Current wording

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.

Previous wording

During the year ended December 31, 2024, the Plaquemines Project had a loss from operations of $217 million, a $30 million, or 16%, increase from $187 million during the year ended December 31, 2023.

Current wording

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.

Previous wording

Operating and maintenance expense was $589 million for the year ended December 31, 2024, a $198 million, or 51%, increase from $391 million during the year ended December 31, 2023. This increase was primarily due to $67 million higher operating costs at the Calcasieu Project to support ongoing commissioning and remediation work and higher legal costs of $49 million, a $48 million increase in operating costs for our LNG tankers with no corresponding costs in 2023, and $14 million in higher operating costs for the Plaquemines Project mainly resulting from an increase in asset retirement obligation, or ARO, accretion.

Current wording

This increase was partially offset by:

Previous wording

•an increase in operating and maintenance expense of $188 million, primarily due to higher operating costs in support of LNG production including costs to support ongoing commissioning and remediation work, personnel costs and insurance costs; and

Current wording

•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.

Previous wording

During the year ended December 31, 2024, corporate, other and eliminations had a loss from operations of $333 million, a $134 million, or 67%, increase from $199 million during the year ended December 31, 2023.

Current wording

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.

Previous wording

We have a limited operational history and we did not generate any LNG sales proceeds prior to 2022. We may incur losses as we continue to construct and develop our projects and explore the development of other potential natural gas liquefaction and export projects.

Current wording

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, pipeline infrastructure projects, and other complementary gas transportation projects and activities.

Previous wording

The operation, commissioning, construction and development of our projects requires significant capital expenditures.

Current wording

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.

Previous wording

We currently estimate that the total project costs for the CP2 Project will be approximately $27.0 billion to $28.0 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. Of the total project costs for the CP2 Project, approximately $4.0 billion had been paid for as of December 31, 2024. Given that we have not executed certain contracts to construct the CP2 Project, including the EPC contract with respect to Phase 2 of the CP2 Project, 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. 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. In addition, we expect to construct longer pipelines for the CP2 Project than for the Calcasieu Project and the Plaquemines Project. Furthermore, our cost estimates might change due to factors such as unexpected delays 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.

Current wording

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 unexpected delays 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.

Previous wording

These estimates do not reflect the potential impact of any new tariffs that have been announced or implemented since December 31, 2024 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, 2024. 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 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.

Current wording

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 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.

Previous wording

We intend to finance the construction and development of the CP2 Project, the CP3 Project, the Delta Project, and any bolt-on expansions or future LNG projects as well as 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 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 financing 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 the CP2 Project, the Delta Project, the CP3 Project or any future project we may develop will be similar to those used for the Calcasieu Project and the Plaquemines Project.

Current wording

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.

Previous wording

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, 2024 (in millions):

Current wording

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:

Previous wording

In addition, we have significant debt and associated interest expense obligations at our subsidiaries, consisting of debt incurred by VGLNG as well as debt incurred by subsidiaries of VGLNG in connection with financing the Calcasieu Project and the Plaquemines Project. We anticipate obtaining significant additional financing and incurring related financing fees and interest expense in connection with the CP2 Project, the CP3 Project, the Delta Project, our pipeline development projects, our LNG tankers, and any bolt-on expansions or future LNG projects.

Current wording

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.

Previous wording

Outstanding debt and associated interest expense obligations of subsidiaries of VGLNG have no recourse to nor are guaranteed by the Company or VGLNG. The following table summarizes our debt and associated interest expense obligations of subsidiaries of VGLNG as of December 31, 2024 (in millions):

Current wording

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:

Previous wording

(2)Excludes $1.5 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 Subsidiaryof this Form 10-K.

Current wording

(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 Subsidiaryof this Form 10-K.

Previous wording

(3)Inclusive of the expected settlements of interest rate swaps that economically hedge the variable rate interest incurred by the Calcasieu Project and the Plaquemines Project. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K, for more information.

Current wording

(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.

Previous wording

Outstanding debt and associated interest expense 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 expense obligations of VGLNG (including $84 million of indebtedness outstanding as of December 31, 2024, that was incurred by one of our subsidiaries and is guaranteed by VGLNG in certain circumstances) as of December 31, 2024 (in millions):

Current wording

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: