DRS/A

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

DRS/A 1 filename1.htm DRS/A

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Confidential Draft Submission No. 2 submitted to the U.S. Securities and Exchange Commission on September 30, 2024. This draft registration statement has not been publicly filed with the U.S. Securities and Exchange Commission, and all information herein remains confidential.

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Venture Global, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

4924

93-3539083

(State or Other Jurisdiction of

Incorporation or Organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer
Identification Number)

1001 19th Street North, Suite 1500

Arlington, VA, 22209

(202) 759-6740

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Michael Sabel

Chief Executive Officer, Executive Co-Chairman and Founder

Keith Larson

General Counsel and Secretary

Venture Global, Inc.

1001 19th Street North, Suite 1500

Arlington, VA, 22209

(202) 759-6740

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

Copies to:

Richard D. Truesdell, Jr., Esq.
Marcel R. Fausten, Esq.
Davis Polk & Wardwell LLP
450 Lexington Avenue
New York, New York 10017
(212) 450-4000

Michael J. Hong, Esq.

David P. Armstrong, Esq.
Ryan J. Dzierniejko, Esq.
Skadden, Arps, Slate, Meagher & Flom LLP
One Manhattan West, 395 9th Ave,
New York, New York 10001
(212) 735-3000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of ‘‘large accelerated filer,’’ ‘‘accelerated filer,’’ ‘‘smaller reporting company’’ and ‘‘emerging growth company’’ in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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EXPLANATORY NOTE

Pursuant to guidance from the Securities and Exchange Commission, we are omitting our unaudited consolidated financial statements and related notes as of June 30, 2024 and for the six months ended June 30, 2024 and 2023 because they relate to historical periods that we believe will not be required to be presented separately in the registration statement at the time it is filed publicly. We intend to include all financial information required by Regulation S-X at the date of such public filing of the registration statement.

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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED , 2024

PRELIMINARY PROSPECTUS

Shares

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Venture Global, Inc.

Class A Common Stock

Venture Global, Inc., or the Company, is offering shares of its Class A common stock.

This is our initial public offering and no public market currently exists for our Class A common stock. We anticipate that the initial public offering price will be between $ and $ per share.

Upon completion of this offering, we will have two classes of common stock, Class A common stock and Class B common stock. Each share of Class A common stock is entitled to one vote per share. Each share of Class B common stock is entitled to ten votes per share. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters, except as otherwise set forth in this prospectus or as required by applicable law. Each outstanding share of Class B common stock will convert automatically into one share of Class A common stock upon any transfer, except for certain exceptions and permitted transfers described in our amended and restated certificate of incorporation. The Class B common stock, which is held by Venture Global Partners II, LLC, or VG Partners, will represent approximately % of the total combined voting power of our outstanding common stock following this offering (or approximately % of the total combined voting power of our outstanding common stock if the underwriters exercise in full their option to purchase additional shares of our Class A common stock).

We intend to apply to list our Class A common stock on , or , under the symbol “VG.”

After the completion of this offering, VG Partners will continue to beneficially own common stock representing more than 50% of the total combined voting power of our outstanding common stock eligible to vote in the election of directors. As a result, we will be a “controlled company” for the purposes of the listing requirements. See “Management—Status as a “Controlled Company” under Listing Standards.”

Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 20.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Share	Total
Public offering price	$	$
Underwriting discounts and commissions⁽¹⁾	$	$
Proceeds to us before expenses	$	$

(1)	See the section titled “Underwriting” for additional information regarding compensation payable to the underwriters.

The underwriters have the option for a period of 30 days to purchase up to an additional shares of Class A common stock from us at the initial public offering price less underwriting discounts and commissions.

The underwriters expect to deliver the shares to purchasers on or about , 2024.


Goldman Sachs & Co. LLC		J.P. Morgan

(in alphabetical order)

Prospectus dated , 2024

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

TABLE OF CONTENTS


	Page
Market and Industry Data		ii
Trademarks and Service Marks		ii
Basis of Presentation		ii
Certain Important Terms		iii
Prospectus Summary		1
Risk Factors		20
Special Note Regarding Forward-Looking Statements		91
Use of Proceeds		95
Dividend Policy		96
Capitalization		97
Dilution		99
Management’s Discussion and Analysis of Financial Condition and Results of Operations		101
LNG Industry Overview		134
Business		149
Management		201
Executive Compensation		209
Certain Relationships and Related Party Transactions		221
Principal Stockholders		225
Description of Capital Stock		227
Description of Indebtedness and Project Financing		235
Material U.S. Federal Income and Estate Tax Consequences for Non-U.S. Holders of Common Stock		248
Shares Eligible For Future Sale		251
Underwriting		254
Legal Matters		262
Experts		262
Where You Can Find More Information		263
Index to Consolidated Financial Statements		F-1

We and the underwriters have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may provide you. We and the underwriters are offering to sell, and seeking offers to buy, shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of Class A common stock.

For Investors Outside of the United States: We and the underwriters have not done anything that would permit this offering, or possession or distribution of this prospectus, in any jurisdiction where action for that purpose is required, other than the United States. Persons outside of the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the shares of our Class A common stock and the distribution of this prospectus outside of the United States.

Through and including , 2024 (25 days after the date of this prospectus), all dealers that buy, sell or trade our Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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MARKET AND INDUSTRY DATA

This prospectus includes industry and market data that we obtained from periodic industry publications, third-party studies and surveys, filings of public companies in our industry and internal company surveys. These sources include government and industry sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable. Although we believe the industry and market data to be reliable as of the date of this prospectus, this information could prove to be inaccurate. Industry and market data could be wrong because of the method by which sources obtained their data and because information cannot always be verified with complete certainty due to the limits on the availability and reliability of raw data, the voluntary nature of the data gathering process and other limitations and uncertainties. In addition, we do not know all of the assumptions regarding general economic conditions or growth that were used in preparing the forecasts from the sources relied upon or cited herein.

TRADEMARKS AND SERVICE MARKS

The Venture Global logos, and other trade names, trademarks, or service marks of Venture Global appearing in this prospectus are the property of Venture Global. Other trade names, trademarks, or service marks appearing in this prospectus are the property of their respective holders. Solely for convenience, trade names, trademarks, and service marks referred to in this prospectus appear without the ^®, ^™, and SM symbols, but those references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or that the applicable owner will not assert its rights, to these trade names, trademarks, and service marks.

BASIS OF PRESENTATION

We have made rounding adjustments to some of the figures included in this prospectus. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that precede them. Unless otherwise indicated, all references to “U.S. dollars,” “dollars” and “$” in this prospectus are to the lawful currency of the United States of America.

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CERTAIN IMPORTANT TERMS

Unless otherwise indicated or the context otherwise requires, as used in this prospectus:

•

Bcf means billion cubic feet;

•

Bcf/d means billion cubic feet per day;

•

Bcf/yr means billion cubic feet per year;

•

bolt-on expansion liquefaction capacity means the incremental capacity that can be generated by our projects as a consequence of potential expansions to our existing or planned projects;

•

COD means the commercial operations date, which is the first day of commercial operations at a project or a phase of a project, as applicable, as specifically defined in the relevant post-COD SPAs, and which does not occur unless and until: (i) all of the facilities comprising the relevant project, or phase thereof, have been completed and commissioned, including any ramp up period, (ii) the project or phase thereof is capable of delivering LNG in sufficient quantities and necessary quality to perform all of its obligations under such post-COD SPAs, and (iii) the applicable project company has notified the customer under the post-COD SPAs;

•

commercial operations means the production period commencing after the occurrence of COD at a project or a phase of a project, as applicable;

•

commissioning or commissioning phase means, with respect to our LNG projects, the phase of development where our facilities undergo certain required performance and reliability testing, which includes (i) the sequential start-up and testing of certain key equipment (e.g., liquefaction trains) as it is installed during construction and (ii) the testing and tuning of the full integrated LNG project after all key equipment and modules have passed their individual performance tests;

•

commissioning cargos means the LNG cargos produced by us during the commissioning phase of an LNG project, which commences once a project produces its first quantities of LNG and ends once a project, or phase thereof, achieves COD. Procceds from the sale of commissioning cargos are recognized in our financial statements as a reduction to the cost basis of construction in progress until assets are placed in service from an accounting perspective, the timing of which may differ from COD. After assets are placed in service from an accounting perspective, the proceeds are recognized through revenue;

•

the Company means Venture Global, Inc., but not its subsidiaries;

•

CP Express means Venture Global CP Express, LLC;

•

CP2 means Venture Global CP2 LNG, LLC;

•

CP3 means Venture Global CP3 LNG, LLC;

•

Delta means Venture Global Delta LNG, LLC;

•

Delta Express means Venture Global Delta Express, LLC;

•

DOE means the United States Department of Energy;

•

DPU means delivered at place unloaded, which, with respect to LNG SPAs, requires the seller to deliver and unload LNG at one or more designated destinations;

•

EPC means engineering, procurement and construction;

•

EPCM means engineering, procurement, and construction management, which entails certain supervision, management, and co-ordination of EPC and other construction interface work;

•

excess capacity or excess LNG means the amount of LNG that is produced by our liquefaction facilities that is in excess of the nameplate capacity;

iii

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•

FERC means the Federal Energy Regulatory Commission;

•

FID means the final investment decision with respect to the development of a project or a phase thereof, which, with respect to an LNG project, requires that the project has secured (i) all of the debt and equity financing arrangements necessary to fully construct, commission, and operate such project or phase thereof and (ii) all of the necessary permits to construct, operate, and export LNG;

•

FOB means free on board which, with respect to LNG SPAs, requires the seller to deliver and load LNG onto the buyer’s LNG tankers at the seller’s export terminal;

•

FTA means a free trade agreement;

•

Gator Express means Venture Global Gator Express, LLC;

•

Henry Hub means the final settlement price (in $ per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin;

•

Legacy VG Partners means Venture Global Partners, LLC;

•

liquefaction train or train means a liquefaction production unit that cools natural gas to a liquid state;

•

LNG means liquefied natural gas, or methane, supercooled to -260°F and converted into a liquid state, which reduces it to 1/600^th of its original volume, enabling large quantities of natural gas to be loaded and shipped by LNG tankers;

•

Mcf/d means million cubic feet per day;

•

MMBtu means million British thermal units;

•

MMt means million tonnes;

•

mtpa means million tonnes per annum, which is a common unit of measurement for annual LNG production;

•

nameplate capacity means, unless the context otherwise requires, the conservative measure of LNG production capability, based on vendor guaranteed LNG output of each of our facilities;

•

natural gas means any hydrocarbons that are gaseous at standard temperature and pressure;

•

NTP means a formal notice to proceed issued under our EPC contracts, procurement contracts or other construction contracts, as applicable;

•

peak production capacity means the total combined amount of LNG that our liquefaction facilities are anticipated to produce, which is the sum of such facility’s expected nameplate capacity and excess capacity (or excess LNG);

•

post-COD SPA means an SPA for the sale and purchase of LNG after COD has occurred for a particular project or phase thereof;

•

Pre-IPO Stockholders means VG Partners and each other holder of shares of our common stock outstanding immediately prior to consummation of this offering;

•

regasification means the process of heating LNG to convert it from a liquid to gaseous state after the LNG is offloaded from an LNG carrier;

•

SPA or LNG SPA means LNG sales and purchase agreement;

•

stick-built means a traditional labor-intensive construction method where raw materials, parts and components are delivered to site for on-site fabrication, assembly and construction by very large workforces;

•

Tcf means trillion cubic feet;

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•

TCP means TransCameron Pipeline, LLC;

•

total contracted revenue means, as of a particular date, the sum, for the remainder of the term for all of our post-COD SPAs then in effect, of (i) the volume weighted average of the fixed facility charge component for all such post-COD SPAs for each project or project phase, multiplied by the contracted volumes for all such post-COD SPAs for the applicable project or project phase, in each case adjusted for inflation (assuming that 17.5% of the fixed facility charge component increases by 2.5% annual inflation every year following the first full year after COD), and (ii) the lifting revenue that would be earned for all such post-COD SPAs, assuming, for illustrative purposes only, all volumes contracted under each such post-COD SPA are lifted at an assumed Henry Hub gas price per MMBtu of $4.00 per MMBtu, in each case using a conversion factor of MMBtu to mtpa of 52. See “Risk Factors—Risks Relating to Our Business—Total contracted revenue is based on certain assumptions and is presented for illustrative purposes only and actual sales under our SPAs may differ materially from such illustrative operating results”;

•

Venture Global, we, our, us or similar terms mean Venture Global, Inc. and its subsidiaries, collectively;

•

VG Commodities means Venture Global Commodities, LLC;

•

VG Partners means Venture Global Partners II, LLC, our controlling shareholder;

•

VGCP means Venture Global Calcasieu Pass, LLC;

•

VGLNG or Venture Global LNG means Venture Global LNG, Inc.; and

•

VGPL means Venture Global Plaquemines LNG, LLC.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that you should consider before deciding to invest in our Class A common stock. You should read this entire prospectus carefully, including the “Risk Factors” section and the consolidated financial statements and the notes to those statements and management’s discussion and analysis thereof included elsewhere in this prospectus, before making an investment decision to purchase our Class A common stock.

Overview

Our Company

Venture Global has fundamentally reshaped the development and construction of liquefied natural gas production, establishing us as a rapidly growing company delivering critical LNG to the world. Our innovative and disruptive approach, which is both scalable and repeatable, allows us to bring LNG to a global market years faster and at a lower cost. We believe supplying this clean, affordable fuel promotes global energy security and is essential to meeting growing global demand.

Natural gas is one of the most important resources worldwide and is required to generate reliable electricity that underpins economic development and drives industry. Once natural gas is supercooled to -260°F, it converts to liquid form and reduces to 1/600th of its original volume, enabling large quantities of natural gas to be loaded and shipped by LNG tankers. The resulting LNG can be transported to international markets that lack domestic supply, displacing more carbon intensive sources of energy such as coal, diesel, and heavy fuel oil, and serving as an integral part of a cleaner energy future. We believe our business model has demonstrated that in a competitive commodity market, lower cost and overall faster delivery wins market share. Our approach capitalizes on both of these advantages, supporting significant additional growth opportunities.

Our Projects

We are commissioning, constructing, and developing five natural gas liquefaction and export projects near the Gulf of Mexico in Louisiana, utilizing our unique “design one, build many” approach. Each project is designed or is being developed to include an LNG facility and associated pipeline systems that interconnect with several interstate and intrastate pipelines to enable the delivery of natural gas into the LNG facility. As illustrated by the chart below, our five current projects are being designed to deliver a total expected peak production capacity of 143.8 mtpa, which consists of an aggregate of 104.4 mtpa expected nameplate capacity and an aggregate of 39.4 mtpa of expected excess capacity. The expected nameplate capacity of our facilities measures the minimum operating performance thresholds guaranteed by the equipment providers, and the expected excess capacity represents the additional LNG that we aim to produce above such guaranteed amounts. Although COD has not yet occurred under the post-COD SPAs for any of our projects, we have been generating proceeds from the sale of commissioning cargos at the Calcasieu Project since the first quarter of 2022, and expect to do so at each of our other projects during commissioning prior to achieving COD for the relevant project or phase of a project.

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(1)	Targets based on, among other things, anticipated timeframes for the receipt of certain regulatory approvals as described in “Business—Governmental Regulation.”

(2)	Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval, among other things, and may change based on design considerations, engagement with contractors, and other factors.

Our Project Development and Construction Approach

The traditional approach to developing large-scale LNG facilities involves very large, highly customized, stick-built projects consisting of two to three liquefaction trains that are constructed almost entirely onsite by vast workforces. In addition, many of these large stick-built projects are built in remote locations far from concentrated sources of experienced construction workforces, adding to their execution risks. Using this traditional approach, construction can last well over five years and in some cases has lasted nearly a decade.

In contrast, our project development and construction approach utilizes proven liquefaction system technology and equipment in a unique mid-scale, factory-fabricated configuration that we developed. Instead of two or three large, complex liquefaction trains, the Calcasieu Project and the Plaquemines Project utilize 18 and 36 mid-scale factory-fabricated liquefaction trains, respectively. We expect to use the same approach and technology at the CP2 Project, the CP3 Project and the Delta Project. Our modules are built and assembled off-site at manufacturing and fabrication facilities in Italy and then shipped to our project sites fully-assembled and packaged for installation, allowing onsite work to progress in parallel. We believe our innovative configuration, long-term equipment contracting strategy and hands-on project management approach significantly reduces construction and installation costs, as well as construction time and schedule risk, thereby allowing us to be more cost-competitive in the LNG market while also producing substantial amounts of commissioning cargos and related cash proceeds. For example, our first project, the Calcasieu Project, began loading cargos of LNG approximately two and a half years after its final investment decision, while significant construction work remained ongoing.

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The chart below illustrates the length of time the Calcasieu Project took to achieve first production of LNG after achieving FID relative to other projects that also achieved FID substantially contemporaneously and are not yet producing LNG.

LOGO

While traditional LNG projects often rely on bespoke designs and configurations, our approach, leveraging factory-fabricated equipment manufactured with our “design one, build many” method, allows us to apply the lessons we learn at each project to our subsequent projects, with the goal of continuously improving our execution, accelerating construction timelines, reducing costs, and expanding production. We believe we will continue to benefit from this virtuous cycle as we grow.

Gas Supply and Transportation

We have entered into a portfolio of natural gas supply agreements with domestic natural gas suppliers to furnish feed gas to the Calcasieu Project and the Plaquemines Project for liquefaction and power generation. We have also entered into multiple transport capacity agreements with interstate pipeline companies to provide natural gas transportation to the Calcasieu Project and the Plaquemines Project via short-run lateral pipelines. Our CP2 Project has already entered into agreements with third parties for substantial firm transportation capacity and is developing its own pipeline. The CP3 Project and the Delta Project will require their own proposed pipeline routes and we aim to enter into transportation agreements with interstate pipeline companies in connection with the CP2 Project, the CP3 Project and the Delta Project as development progresses.

LNG Sales – Commissioning

By design, conventional, stick-built projects generally only engage in several months of commissioning production, thereby limiting the number of cargos produced before full commercial operations occur. Due to our unique modular development approach and configuration consisting of many mid-scale liquefaction trains, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-scale liquefaction trains. The commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction.

This important reliability and technical requirement results in earlier production of LNG than with traditional LNG facilities. We believe this earlier production of LNG positions us to produce a substantial number of commissioning cargos for each of our LNG projects, generating proceeds that may be used to support any remaining construction work or fund subsequent projects and future growth. As an example of this, on March 1, 2022, we announced the successful loading and departure of our first cargo of LNG from the Calcasieu Project, just over two and a half years from our final investment decision for the project. By , 2024, we had loaded and sold LNG commissioning cargos and received $ billion in gross proceeds from such commissioning cargos.

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LNG Sales – Post-COD SPAs

The project companies for the Calcasieu Project, the Plaquemines Project and the CP2 Project have signed LNG sales and purchase agreements, or SPAs, to sell LNG based on a pre-determined pricing formula that commences after we achieve the commercial operations date, or COD, of the relevant project or phase thereof. Under each such post-COD SPA, COD does not occur unless the applicable project company has notified such customer that (i) all of the project’s facilities have been completed and commissioned, including any ramp up period, and (ii) the project is capable of delivering LNG in sufficient quantities and necessary quality to perform all of its obligations under such post-COD SPA.

As of , 2024, we have executed mtpa of such post-COD SPAs with a well recognized set of third party customers that we believe constitute one of the strongest portfolios of institutional LNG buyer credits in the world. Approximately % of our contracted post-COD SPAs – or mtpa of such mtpa – are 20-year fixed price agreements, providing a long-term stream of contracted cash flow. We have also executed mtpa of post-COD SPAs on a short- and medium-term basis and we plan to continue to optimize our portfolio balancing profit, duration, and risk.

Excess Capacity

LNG projects are typically able to achieve production beyond their guaranteed nameplate capacities. For many traditional large international stick-built projects, generating additional production capacity generally requires substantial incremental equipment and construction, with associated injections of capital. By comparison, we believe our projects will have the potential to produce materially beyond their nameplate capacities, with modest incremental capital investment because of our modular design as well as redundancy features inherent in our project design.

We aim to construct and maintain LNG facilities that are capable, in most cases, of producing excess capacity of at least 30% of their guaranteed nameplate capacity, which provides the potential for additional cash proceeds from our projects. Any such excess capacity will generally be available to us to sell on a short-, medium-, or long-term basis, providing flexibility to optimize pricing. With respect to the Calcasieu Project, our inaugural project, we expect to produce excess capacity of slightly less than 30% of its nameplate capacity and we have contracted to sell a portion of such excess capacity to a third-party pursuant to a long-term SPA.

Optimization and Bolt-on Expansion Opportunities

Our projects also offer potential optimization, increased capacity and expansion opportunities. In particular, our projects are sited and designed with the intention of allowing for bolt-on expansions, incorporating laydown area, redundancies across the facility infrastructure and our mid-scale factory-fabricated liquefaction trains. Subject to receiving the requisite regulatory approvals, we intend to pursue the development of these expansion opportunities beyond our current combined expected nameplate capacity of 104.4 mtpa. Any incremental equipment would benefit from pre-existing plant facilities and related infrastructure (such as marine offloading facilities, LNG storage tanks and perimeter walls). We aim to place up to an aggregate of 35.2 mtpa of additional bolt-on expansion liquefaction capacity of incremental modular mid-scale liquefaction trains at most of our current projects.

Potential Additional LNG Projects and Further Integration

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engaged in substantial activities to establish complementary pipeline projects, LNG tanker and regasification business lines that could be leveraged for other potential natural gas liquefaction and export projects in the future. Our experienced project execution team, who have deep industry expertise in the LNG, shipping, midstream and construction industries, possess the institutional agility and capital to rapidly evaluate and act upon opportunities as they arise and we believe differentiate us from our competitors.

Pipeline Projects

We are in the advanced stages of development to establish complementary gas transportation for our development projects. As an example, we have partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, and entered into a joint development agreement with one of their affiliates. Under this agreement, we have committed to jointly develop, permit and site the approximately 190 mile Blackfin pipeline project, which upon construction is expected to include a long-haul 48-inch intrastate pipeline designed to facilitate the transportation of Permian sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline. We believe that gas transportation projects such as this will help further integrate major sources of gas supply with the projects we may develop in the future.

Shipping

In order to vertically integrate our business and expand our customer base to premium markets that have no or limited LNG transportation resources, we have contracted to acquire nine LNG tankers being constructed by two of the premier shipbuilders in South Korea, with two already delivered. The remaining LNG tankers are under construction and are scheduled to be delivered on a rolling basis through 2026. We have also executed two short-term charters for additional LNG tankers, which were delivered in August and September 2024, bringing our total shipping portfolio to a total of eleven tankers. We believe these LNG tankers will support our ability to optimize LNG marketing and sales and differentiate us from many other LNG exporters in North America.

Regasification

We are also pursuing opportunities to secure LNG regasification capacity in key import markets. As part of this initiative, we have acquired firm regasification facility capacity at the largest LNG regasification terminal in Europe, Grain LNG, in the United Kingdom, which we expect will allow us to import 42 LNG cargos per year from approximately 2029 until 2045 (apart from a limited period). Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, beginning in 2025. Our capacity will account for approximately 25% of the total terminal capacity at Alexandroupolis, or approximately 12 cargos annually. We believe these contracted capacities will allow us to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers. As in the case of our shipping business, many LNG developers have elected to forego integrating regasification into their broader business. Relatedly, many LNG customers lack direct access to regasification capacity. We believe our regasification access will allow us to offer spot and term customers a differentiated service, ultimately positioning us to win market share.

Our Strengths

Our business has a number of competitive strengths, including the following:

•

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developer achieved such a milestone for more than a single large-scale infrastructure project in the world. We expect to increase our LNG production capacity further as we continue our work to optimize our existing projects and develop the CP2 Project, the CP3 Project, the Delta Project, bolt-on and other expansion opportunities, and other investments.

•

Accelerated construction schedule and low-cost LNG model. We believe that our disruptive and innovative configuration and owner-led engineering, procurement and construction approach reduces our construction and installation costs, construction time and construction schedule risk, thereby reducing overall project costs and enabling us to produce and sell LNG on an accelerated basis to our customers, as a result of the following:

•

Focus on minimizing the time to first LNG. At our first project, the Calcasieu Project, we were able to produce and load LNG for sale approximately two and a half years after the final investment decision, while simultaneously commissioning and constructing the facility, which is substantially faster than the industry average of five years. Although our second project is designed to produce twice the amount of LNG as our first project, we currently aim to improve on this pace for first production of LNG, as well as accelerate bringing subsequent trains online at the Plaquemines Project and the other projects we develop. Given the current status of construction progress, we are targeting to produce first LNG at the Plaquemines Project in , 2024 and shortly thereafter, begin to generate commissioning cargos and associated proceeds.

•

Construction and installation execution. Manufacturing our mid-scale, factory-fabricated liquefaction trains, power equipment, gas pre-treatment modules and pipe racks off-site at fabrication facilities allows site works to progress in parallel. Our liquefaction trains and pre-treatment modules are tested and delivered ready to install, reducing on-site labor and potential weather risk while shortening construction timelines and improving overall project safety. Fabrication and installation efficiencies are achieved as the various trains, equipment, and modules are installed on-site and commence production incrementally. Using our “design one, build many” approach, lessons learned from construction, installation, and commissioning work at the Calcasieu Project are being carried over to the Plaquemines Project and our subsequent projects. Further, using our owner-led development model, we actively manage the construction activity and the schedule for certain scopes of work undertaken by our key contractors. In addition, we have built an internal EPCM capability, securing a team of experienced leaders and professionals from the EPC industry, primarily with prior relevant experience constructing the Calcasieu Project and the Plaquemines Project facilities.

•

Incremental commissioning and LNG production proceeds provide substantial cash proceeds. As each project’s liquefaction trains are brought online, sequentially, and early in construction, the project incrementally produces greater quantities of LNG that may be sold into the market. Once all individual components have been commissioned, production continues while we complete full commissioning of the integrated facility and conduct any carryover or rectification work. During such process, we complete performance testing of the entire fully-integrated facility and validate reliable operational performance. We expect that each project’s construction plan and sequencing will be designed to allow LNG to be produced, stored and loaded onto ships for export, and sold as commissioning cargos, generating cash proceeds.

•

Substantial ownership and direct oversight of a diversified LNG project portfolio. Venture Global seeks to own all or substantially all of the equity ownership in its current five LNG projects and any future projects. As of the date of this prospectus, we own 100% of the common equity interests in the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project and the Delta Project. Upon COD for the Calcasieu Project, we expect our ownership of the common equity interests in the Calcasieu Project to be reduced to approximately % (assuming COD in and payment of certain distributions in cash), after adjusting for the automatic conversion of the convertible

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preferred units in Calcasieu Holdings held by an outside equity investor. We believe that our significant ownership stake in our projects provides us with full managerial control, facilitating nimble decision-making and speed of execution.

•

Stable, long-term cash flows and valuable commissioning cargos and excess cargos.

•

Long-term take-or-pay contracts with highly creditworthy offtakers. We anticipate that our business model will provide us with stable cash flows as a result of our long-term take-or-pay contracts to sell LNG. As of , 2024, we have executed mtpa of post-COD SPAs with a set of third party customers that we believe constitute one of the strongest portfolios of institutional LNG buyer credits in the world. The entire expected nameplate capacity for the Calcasieu Project (10 mtpa) and the Plaquemines Project (20 mtpa), and mtpa of the CP2 Project, have been contracted under such SPAs. Our third-party post-COD SPAs as of , 2024 represent expected total contracted revenue of approximately $ billion over the life of such SPAs. Our total contracted revenue is illustrative only and is based on a number of important assumptions. The weighted average life of all of our post-COD SPAs is approximately 19 years, providing a long-term runway of reliable cash flows.

•

Valuable and substantial commissioning cargo and excess cargo cash proceeds. Prior to achieving COD under our post-COD SPAs, our post-COD SPAs permit us to generate and sell commissioning cargos to customers at market-based prices, which we believe can unlock significant value to Venture Global. This approach has the potential dual benefit of helping to mitigate risks related to commencement of commercial operations and generating significant cash flow that can be reinvested into the business. For example, since the commencement of commissioning work, the Calcasieu Project has loaded and sold commissioning cargos as of , 2024 and received $ billion in gross proceeds from such commissioning cargos. In addition, after COD occurs under our post-COD SPAs, to the extent not already contracted with third parties, we can sell any LNG generated by our projects above the nameplate capacity to customers at market-based prices, providing potential revenue upside over the long term. Proceeds generated from the sale of commissioning cargos and excess cargos provide us with additional cash proceeds and contingency to support project completion and can help fund the development of our other projects.

•

Strategic project locations with capacity for substantial expansions. We are developing our current portfolio of projects on strategic locations in Louisiana, which we believe have significant advantages relative to other locations in the United States. Our current projects are located near or within a reasonable distance from several major interstate and intrastate natural gas pipelines with available capacity that we believe will be sufficient to supply the feed gas required for our projects. We believe these project sites are well-placed and allow us to access liquid and robust natural gas trading areas and obtain competitively priced natural gas for our customers. Our current project portfolio offers geographic diversification within Louisiana. The Calcasieu Project, the CP2 Project and the CP3 Project are located at or near the mouth of the Calcasieu Ship Channel, and the Plaquemines Project and the Delta Project are located approximately 300 miles east and are sited next to the Mississippi River, each of which provides ready access to our facilities from the Gulf of Mexico. Since they are located at or near the mouth of the Calcasieu Ship Channel, the Calcasieu Project, the CP2 Project and the CP3 Project sites’ geography also allow for faster entry into and exit from our berthing docks relative to many other facilities in the region. Our current projects are also located in close proximity to major population centers, providing ease of access for workers and transportation of materials. The Calcasieu Project and Plaquemines Project sites also benefit from full road and water access, and buffer lands to facilitate deliveries and serve as laydown areas, and we expect sites of the CP2 Project, the CP3 Project and the Delta Project to benefit from the same access and buffer lands. We believe our current project sites provide significant opportunities for bolt-on expansions that would benefit from

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pre-existing plant facilities and related infrastructure (such as common pipe racks, marine offloading facilities and perimeter walls). Moreover, we believe Louisiana is a favorable legal, regulatory and political jurisdiction for our projects.

•

LNG shipping and regasification capabilities to supply new customers and to support existing customers. We are assembling a fleet of at least 11 LNG tankers to provide additional optionality to spot and term customers and to service contracts with transportation or delivery components. We have also acquired firm regasification facility capacity at the Grain LNG terminal, Europe’s largest LNG regasification terminal, in the United Kingdom to import 42 LNG cargos per year from approximately 2029 until 2045 (apart for a limited period). Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, beginning in 2025, which equates to approximately 12 cargos annually. We believe that such shipping and regasification capabilities will support our ability to optimize LNG marketing, sales, and logistics to reach new markets and customers.

•

Experienced management team aligned with stakeholders.

•

Industry-leading team. Our management team possesses deep experience across all parts of the LNG industry with a proven development and operational track record. We believe that the collective quality and experience of our team, coupled with our relationships with our contractors, customers and consultants, enable us to move quickly to continue to take advantage of the North American LNG market opportunity. Further, we have assembled a broader team of over employees globally.

•

Exemplary safety record. Notwithstanding the rapid construction progress that we have achieved, our Calcasieu Project and Plaquemines Project have maintained exemplary safety records. Our projects have substantially outperformed the national average of a 2.1 Total Recordable Incident Rate, or TRIR, for 2023, which represents US Bureau of Labor Statistics Heavy Construction Industry recordable incidents per one hundred workers per year. On average, our safety record exceeds the industry average by with a TRIR of for approximately million hours of work on an aggregate basis as of , 2024. As of , 2024, the Calcasieu Project executed million work hours with a TRIR of and the Plaquemines Project executed million work hours with a TRIR of .

•

Committed to environmental and community initiatives. Our management team is committed to an environmentally sound and community-friendly approach to the development and operation of our projects in conjunction with our key stakeholders. We aim to establish close relationships with the communities where our projects are located by fueling local economic growth, job creation, and skills training, while also engaging in wetlands restoration work. In addition, we have decided to use environmentally-sensitive design features (e.g., electrically-driven motors, air cooling throughout the projects, combined cycle power, and state of the art, full containment storage tanks which seek to eliminate methane release from stored LNG), and are pursuing an initiative to develop certain CCS facilities for our projects.

Our competitive strengths are subject to several risks and competitive challenges. Please read “Risk Factors” and “Business—Competition.”

Our Business and Growth Strategies

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from significant deep-water frontage. Although we have a limited operating history and did not generate any proceeds prior to 2022, as of , 2024, we have raised approximately $ billion of capital and generated over $ billion in gross proceeds from sales of commissioning cargos, resulting in over $ billion of net proceeds. We have also executed mtpa of post-COD SPAs, representing % of the volume of SPAs contracted by producers on the US Gulf Coast since and expect total contracted revenue of approximately $ billion over the life of such SPAs. Notwithstanding these accomplishments, we are acutely focused on further growth and plan on pursuing the following three core drivers to expand our scale, profitability and impact on the global energy industry.

Develop, Construct and Operate New LNG Facilities – We are currently developing and permitting three projects beyond our two existing projects: the CP2 Project, the CP3 Project and the Delta Project. Based on our success developing, permitting, financing and constructing the Calcasieu Project and the Plaquemines Project, we are confident in our ability to execute these additional projects and expect each facility to increase the cash proceeds we generate from LNG sales over time in a compounding fashion due to the following factors:

•

Rapid Return of Capital Enables Parallel Project Development – Unlike most industrial project developers who must wait years to recoup invested capital, our innovative approach to development allows us to generate cash proceeds from commissioning cargos at our projects which can potentially surpass the total costs of the projects prior to COD. Further, this accelerated return profile can also allow us to shift capital from one project under construction to a subsequent project, enabling us to develop multiple projects in parallel. In the case of the CP2 Project, we plan on utilizing cash proceeds from the Calcasieu Project and the Plaquemines Project to fund a substantial portion of construction.

•

Optimized LNG Sales – By recycling cash proceeds from one project to fund our subsequent projects, we aim to reduce our need for a critical mass of long-term SPAs, which are predominantly lower priced than short- and medium- term SPAs and typically required to support traditional project financing. Any production capacity from our projects that is not otherwise committed can be sold on a short-, medium- or long-term basis, including on a spot basis, providing flexibility to optimize the pricing for such capacity and allowing us to balance profit, duration and risk. As a result, while the Plaquemines Project and the CP2 Project are both designed as 20 mtpa nameplate capacity facilities, we expect the cash proceeds generated by the optimized cash proceeds at the CP2 Project to exceed the substantial LNG sales at the Plaquemines Project. We believe this virtuous cycle will compound with subsequent projects.

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Bolt-On Expansions

•

A distinctive benefit of our unique design is the ability to flexibly and economically expand liquefaction capacity by adding additional factory-made liquefaction trains and installing them at our existing projects. Bolt-on expansions were contemplated in the initial design and siting of our facilities. Such expansions benefit from substantial redundancy to support additional production capacity.

•

We intend to pursue these opportunities in the future and believe that we have the ability to add up to a total of 35.2 mtpa of bolt-on expansions across the Calcasieu Project, the Plaquemines Project, the CP2 Project, and the Delta Project as outlined below. No such expansions are currently contemplated at the CP3 Project due to its considerable 30 mtpa expected nameplate capacity.

•

We aim to self-fund these expansions, reducing our reliance on lower-priced, longer-term contracts that are typically required to support traditional project financing. This strategy enables us to sell the production capacity from any such expansions on a short-, medium- or long-term basis, including on a spot basis, thereby providing flexibility to continually optimize the pricing for such capacity based on market conditions.

LOGO

(1)	Targets based on, among other things, anticipated timeframes for the receipt of certain regulatory approvals as described in “Business—Governmental Regulation.”

(2)	Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors.

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

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Vertical Integration and Opportunistic Investment

•

In addition to our core business, our liquefaction and export projects, we regularly evaluate complementary businesses that have the potential to strengthen our vertical integration, drive growth and support margin expansion. We have already engaged in substantial activities to establish complementary gas transportation, LNG tanker and regasification business lines that we plan to leverage in connection with our core assets.

•

Beyond our LNG facilities under development, the bolt-on expansions, and complementary businesses described above, we consistently explore opportunities, both domestic and international, to develop or acquire other LNG projects and further grow our footprint. We believe our design and approach are adaptable and exportable, providing us ample opportunities, both domestically and internationally, beyond our current development pipeline.

LOGO

Risk Factors

Before you invest in our Class A common stock, you should carefully consider all the information in this prospectus, including the risks associated with our business and this offering set forth under the heading “Risk Factors.” These risks include, among others:

•

Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty.

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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.

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Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds. 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 proceeds for any future period or for any of our other projects.

•

We have not entered into SPAs with customers for the total expected nameplate capacity at the CP2 Project, the CP3 Project or the Delta Project and our failure to enter into final and binding contracts for an adequate portion or any of, or to otherwise sell, the expected nameplate capacity of any of our projects, could have a material adverse effect on our 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.

•

Our customers may terminate our SPAs if certain conditions are not met or for other reasons.

•

Our ability to generate cash under our post-COD SPAs 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.

•

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.

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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.

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•

Our limited diversification could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

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We are dependent on the strategic direction of Michael Sabel, our Chief Executive Officer, Executive Co-Chairman and Founder, and Robert Pender, our Executive Co-Chairman and Executive Co-Chairman of the Board and Founder.

•

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.

•

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 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 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.

•

We have not entered into all of the definitive agreements for the CP2 Project, the CP3 Project or the Delta Project 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.

•

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.

•

Our estimated costs for our projects have been, and continue to be, subject to change due to various factors.

•

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, prospects and the price of our Class A common stock.

•

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.

•

The natural gas liquefaction system and mid-scale, factory-fabricated 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.

•

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 face competition based upon the international market price for LNG.

•

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 fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.

•

If we are unsuccessful in our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.

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•

VG Partners will continue to have significant influence over us after this offering, 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.

•

An active, liquid trading market for our Class A common stock may not develop or be sustained, and there is the possibility of significant fluctuations in the price of our Class A common stock

•

We cannot guarantee that we will pay 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.

For a discussion of these and other risks, see “Risk Factors.”

Our Founders

Robert Pender and Michael Sabel, our founders, control Venture Global Partners II, LLC, or VG Partners, which is our controlling stockholder. Prior to this offering, VG Partners owned approximately % of all series of our common stock outstanding and, upon consummation of this offering, VG Partners will own approximately % of our outstanding Class B common stock.

Corporate Information

Our direct subsidiary, VGLNG, which owns all of our subsidiaries, was originally established in 2013 by our founders. As part of certain corporate reorganization transactions, or Reorganization Transactions, Venture Global, Inc. was formed in 2023 and became the 100% owner of VGLNG. For more information about the Reorganization Transactions, see “Certain Relationships and Related Party Transactions—Reorganization Transactions.”

We are a holding company and have no direct operations. All of our business operations are conducted through our subsidiaries, including VGLNG. Our principal asset is the equity interest in VGLNG, which, together with its subsidiaries, owns substantially all of our operating assets. As a result, we are dependent on the ability of our subsidiaries to generate revenues and to make loans, pay dividends and make other payments to generate the funds necessary to meet our financial obligations and to pay dividends to stockholders, if any. The below chart illustrates our current corporate organizational structure immediately after consummation of this offering.

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LOGO

Notes:

(1)	Simplified organizational chart that does not include all legal entities. All ownership is 100% of the existing common equity of each entity listed unless otherwise noted.

(2)

The ownership of Calcasieu Pass Funding, LLC includes a redeemable preferred equity investment by a third party fund associated with Stonepeak Infrastructure Partners, or Stonepeak Fund II, of certain redeemable preferred units that entitles Stonepeak Fund II to certain distributions on its investment, either in the form of permitted cash distributions from available cash at Calcasieu Pass Funding, LLC or accrued distributions on the funding face value of the preferred units. As of , 2024, we owned 100% of all the outstanding common units of Calcasieu Pass Funding, LLC, while Stonepeak Fund II owned 100% of all of the outstanding redeemable preferred units of Calcasieu Pass Funding, LLC. As of , 2024, the aggregate outstanding amount of the redeemable preferred units was $ billion. For more detail, see “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Funding, LLC Preferred Units.”

(3)

The ownership of Calcasieu Pass Holdings, LLC includes a convertible preferred equity investment by a third party fund associated with Stonepeak Infrastructure Partners, or Stonepeak Fund I, of certain convertible preferred units that entitles Stonepeak Fund I to certain distributions in kind in the form of additional preferred units or in cash (as elected by Calcasieu Pass Holdings, LLC), in the form of additional preferred units. As of , 2024, and upon the occurrence of certain conditions, the convertible preferred units are expected to convert to a number of Class B common units of Calcasieu Pass Holdings, LLC equal to approximately % of the common units of Calcasieu Pass Holdings, LLC. For more detail, see “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Holdings, LLC Preferred Units.”

For more information about the risks of investing in a holding company, see our “Risk Factors” elsewhere in this prospectus.

Our principal executive offices are located at 1001 19^th Street North, Suite 1500, Arlington, VA, 22209, and our telephone number is (202) 759-6740. Our internet address is www.venturegloballng.com. Our website, information on our website or any other website is not incorporated by reference in this prospectus and is included in this prospectus as an inactive textual reference only.

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THE OFFERING

Issuer

Venture Global, Inc.

Class A common stock offered by us

Option by the underwriters to purchase additional shares of Class A common stock

Class A common stock to be outstanding after this offering

shares (or shares if the underwriters exercise in full their option to purchase additional shares)

Class B common stock to be outstanding after this offering

shares. In connection with the consummation of this offering, Class A common stock held by VG Partners immediately prior thereto will convert into an equal number of shares of Class B common stock.

Use of proceeds

We estimate that the net proceeds to us from the sale of our Class A common stock in this offering will be approximately $ billion, or approximately $ billion if the underwriters exercise their option to purchase additional shares in full, assuming an initial public offering price of $ per share (the midpoint of the range set forth on the cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses.

Each $1.00 increase (decrease) in the public offering price per share would increase (decrease) our net proceeds, after deducting estimated underwriting discounts and commissions, by $ million (assuming the number of shares of our Class A common stock offered by us, as set forth on the cover of this prospectus, remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares). We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares in the number of shares of our Class A common stock offered by us would increase (decrease) our net proceeds, after deducting estimated underwriting discounts and commissions, by $ million (assuming the public offering price remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares).

We intend to use the net proceeds from this offering, for general corporate purposes, including, but not limited to, funding our continuing operations, our LNG tanker milestone payments and our expected pre-FID capital expenditures with respect to the CP2 Project, the CP3 Project and the Delta Project. See “Use of Proceeds” for more information.

Voting rights

Upon completion of this offering, we will have two classes of voting common stock, Class A common stock and Class B common stock.

Shares of our Class A common stock are entitled to one vote per share.

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Shares of our Class B common stock are entitled to 10 votes per share.

Holders of Class A common stock and Class B common stock will vote together as a single class on all matters (including the election of directors) submitted to a vote of stockholders, except as otherwise provided in our amended and restated certificate of incorporation or as required by applicable law. See “Description of Capital Stock.”

Conversion rights

Shares of our Class A common stock are not convertible into any other class of shares.

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. In addition, each share of Class B common stock will convert automatically into one fully paid and nonassessable share of Class A common stock upon any transfer of such share, except for certain permitted transfers described in our amended and restated certificate of incorporation. See “Description of Capital Stock—Common Stock—Conversion, Exchange and Transferability.”

Concentration of control

Upon completion of this offering, VG Partners will beneficially own all outstanding shares of Class B common stock, representing % of the total combined voting power of our outstanding common stock (or % of the total combined voting power of our outstanding common stock if the underwriters exercise their option to purchase additional shares in full). Accordingly, we will be a “controlled company” under the corporate governance rules of , and VG Partners will have the ability to control the outcome of matters submitted to our stockholders for approval, including the election of our directors and the approval of any change in control transaction. See “Principal Stockholders” and “Description of Capital Stock—Common Stock—Voting Rights.”

Risk factors

You should carefully read and consider the information set forth in the section entitled “Risk Factors” beginning on page 18, together with all of the other information set forth in this prospectus, before deciding whether to invest in our Class A common stock.

Proposed stock exchange symbol

We intend to apply to list our Class A common stock on under the symbol “VG.”

The number of shares of Class A common stock that will be outstanding after this offering is based on shares of Class A common stock outstanding as of , 2024, and excludes:

•

shares of Class A common stock issuable on the exercise of stock options outstanding as of , 2024 under our 2023 Stock Option Plan with a weighted-average exercise price of $ per share;

•

shares of Class A common stock reserved for future issuance under our new omnibus incentive plan, or the 2024 Plan, which will be adopted in connection with this offering, as well as any future increases, including annual automatic evergreen increases, in the number of shares of Class A common stock reserved for issuance under our 2024 Plan; and

•

shares of Class A common stock reserved for future issuance upon the exchange of shares of Class B common stock on a one-for-one basis.

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The number of shares of Class B common stock that will be outstanding after this offering is based on the automatic conversion of shares of Class A common stock held immediately prior to the completion of this offering by VG Partners into an equal number of shares of our Class B common stock, which will occur immediately prior to the completion of this offering.

Except as otherwise indicated, all information in this prospectus assumes:

•

an initial public offering price of $ per share, which is the midpoint of the estimated public offering price range set forth on the cover page of this prospectus;

•

the filing and effectiveness of our amended and restated certificate of incorporation and the effectiveness of our amended and restated bylaws, each of which will occur immediately prior to the completion of this offering;

•

the -for-1 stock split on our Class A common stock to be effected in connection with this offering, immediately prior to the automatic conversion of certain shares of Class A common stock described in the following bullet;

•

the automatic conversion of shares of Class A common stock held immediately prior to the completion of this offering by VG Partners into an equal number of shares of our Class B common stock, which will occur immediately prior to the completion of this offering; and

•

no exercise of the underwriters’ option to purchase up to additional shares of Class A common stock from us in this offering.

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SUMMARY CONSOLIDATED FINANCIAL AND OTHER DATA

The following summary consolidated financial data of the Company should be read in conjunction with, and are qualified by reference to, the information under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this prospectus. The consolidated statement of income data for the years ended December 31, 2023, 2022 and 2021, and the consolidated balance sheet data as of December 31, 2023 and 2022 are derived from, and qualified by reference to, the audited consolidated financial statements of the Company included elsewhere in this prospectus, and should be read in conjunction with those consolidated financial statements and notes thereto. The summary financial data in this section are not intended to replace our audited consolidated financial statements and related notes appearing at the end of this prospectus.


	Year Ended December 31,
	2023			2022			2021
	(in millions, except share and per share data)
Statement of Operations Data:
Revenue	$	7,897		$	6,448		$	—
Operating expense:
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,684			2,093			—
Operating and maintenance expense		391			140			58
General and administrative		224			191			89
Development expense		490			311			188
Depreciation and amortization		277			158			6
Insurance recoveries, net of loss from hurricane		(19	)		—			(4	)

Total operating expenses		3,047			2,893			337

Income (loss) from operations		4,850			3,555			(337	)

Other income (expense):
Interest income		172			18			—
Interest expense, net		(641	)		(592	)		(52	)
Gain on derivatives, net		174			1,212			38
Gain (loss) on embedded derivative		—			(14	)		12
Loss on financing transactions		(123	)		(635	)		(97	)

Total other income (expense)		(418	)		(11	)		(99	)

Income (loss) before income tax expense		4,432			3,544			(436	)

Income tax expense		816			447			—

Net income (loss)		3,616			3,097			(436	)

Less: Net income attributable to redeemable stock of subsidiary		130			118			107
Less: Net income (loss) attributable to non-controlling interests		805			1,121			(187	)

Net income (loss) attributable to stockholders and members	$	2,681		$	1,858		$	(356	)

Earnings per share:
Basic earnings (loss) per share
Net income (loss) attributable to common stockholders per share—basic	$	5,855		$	4,266		$	(817	)
Weighted average number of shares of common stock outstanding—basic		457,896			435,500			435,500
Diluted earnings (loss) per share
Net income (loss) attributable to common stockholders per share—diluted	$	5,656		$	4,266		$	(817	)
Weighted average number of shares of common stock outstanding—diluted		474,033			435,500			435,500

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


	Year Ended December 31,
	2023			2022			2021
	(in millions, except share and per share data)
Cash flow data:
Net cash from (used by) operating activities	$	4,550		$	3,702		$	(503	)
Net cash used by investing activities		(8,725	)		(2,900	)		(2,078	)
Net cash from financing activities		7,635			235			3,623
Segment income (loss) from operations:
Calcasieu Pass Project	$	5,598		$	4,042		$	(85	)
Plaquemines Project		(187	)		(269	)		(158	)
CP2 LNG Project		(362	)		(34	)		(15	)
Corporate and other⁽¹⁾		(199	)		(184	)		(79	)

Total	$	4,850		$	3,555		$	(337	)

(1)	Includes costs associated with the CP3 Project, the Delta Project, certain other development stage projects, our shipping business and certain corporate activities.


	As of
	December 31, 2023		December 31, 2022
	(in millions)
Balance Sheet Data:
Cash and cash equivalents	$	4,823	$	618
Total assets		28,463		15,097

Total liabilities		24,993		13,333

Total stockholders’ equity (deficit)	$	2,085	$	509

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

RISK FACTORS

An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below, together with all other information contained in this prospectus, before making an investment in our Class A common stock. If any of the following risks were to occur, our business, financial condition, results of operations and cash flow could be materially adversely affected. In that case, the trading price of our Class A common stock could decline, and you could lose all or part of your investment.

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. You are strongly encouraged to consult your own professional advisors (including tax and regulatory) before deciding to invest in our Class A common stock.

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).

Our ability to sell LNG commissioning cargos depends on our ability to successfully market, produce, load and, in some cases, deliver commissioning cargos during the commissioning of each of our projects prior to achieving COD. Although we have generated proceeds from the sales of commissioning cargos at the Calcasieu Project since the first quarter of 2022 and we expect to do so at each of our other projects during commissioning prior to the relevant COD, such sales of commissioning cargos are subject to a number of material uncertainties and risks. As a result, the proceeds we have generated from the sales of commissioning cargos from the Calcasieu Project to date may not be indicative of the proceeds from such sales for any future period for the Calcasieu Project or for any of our other projects. See “—Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds. 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 proceeds for any future period or for any of our other projects.”

Our ability to generate sales of LNG following COD at each of our projects depends on our ability to successfully commence and maintain deliveries under our post-COD SPAs. Such revenues can be further supplemented if we are able to produce and sell LNG in excess of the nameplate capacity of our projects. We will not generate any revenues or operating cash flow under our post-COD SPAs (including the six 20-year LNG sale and purchase agreements for the Calcasieu Project, or the Calcasieu Foundation SPAs), or from sales to third parties of excess LNG until we have achieved COD for the relevant project. We are currently targeting a COD for the Calcasieu Project in and a COD for the Plaquemines Project in for Phase 1 and for Phase 2. Assuming timely receipt of required regulatory approvals, COD for the CP2 Project is currently targeted to occur in for Phase 1 and for Phase 2 of the CP2 Project. The CP3 Project and the Delta Project are still in early stages of development. The timeline for both projects remains to be determined and will depend on, among other things, obtaining the necessary regulatory approvals and financing for each project. However, there is no guarantee that we will achieve such CODs within those timeframes or at all. See “—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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

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

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.

Prior to July 2014, we conducted no business or operations and we recorded no revenues or expenses. 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.

Our activities to date have included organizational efforts related to the development and construction of our projects, including but not limited to:

•

raising capital;

•

securing options to lease and leasing our project sites;

•

negotiating and planning with various contractors for the development and production of such sites;

•

negotiating SPAs with purchasers;

•

negotiating and entering into construction contracts with construction contractors; and

•

procuring gas transportation and supply.

In addition, the proceeds we have generated to date are solely proceeds generated from sales of commissioning cargos from the Calcasieu Project, may not be indicative of proceeds from such sales for any future period for the Calcasieu Project or for any of our other projects, or of our future results of operations more generally. See “—Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds. 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 proceeds for any future period or for any of our other projects.”

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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 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.

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

Our ability to generate such proceeds 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, any 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. In addition, 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, either from the Calcasieu Project or any other project, in the future. In addition, because commissioning cargos are not sold under post-COD SPAs and are instead sold on varying terms, including in some instances on a forward basis, proceeds from such commissioning cargos may vary significantly depending on, among other factors, prices and market conditions in the international LNG markets, global LNG freight rates, and on the timing of when a contract for sale is executed. As such, the amount of any proceeds that we may generate from the sale of commissioning cargos and our profitability relating to such sales is largely dependent on the strength of international LNG markets, as primarily reflected in the spot price for LNG at the time a contract for sale of commissioning cargos is executed. Historically, the spot price for LNG has varied significantly, which has impacted the amount of proceeds we have generated. For example, the average month-end spot price for U.S. Gulf Coast LNG from $ in , to $ in . During the same period, the gross proceeds we received from sales of commissioning cargos from the Calcasieu Project from $ ($ in net proceeds after deducting net cash paid for natural gas, which primarily includes the net cost of purchasing and transporting feed gas) for the period ended , to $ ($ in net proceeds, after deducting net cash paid for natural gas) for the period ended . See “—Risks Relating to the LNG Industry—We face competition based upon the international market price for LNG” and “—Risks Relating to the LNG Industry—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 and the price of our Class A common stock.”

We may at times contract commissioning cargos on a forward basis and, as a result, these sales of commissioning cargos may be uncorrelated with movements in spot LNG prices. For example, the average month-end spot price for U.S. Gulf Coast LNG from $ in the quarter of , to $ in the quarter of . During the same period, however, the gross proceeds we received from sales of commissioning cargos from the Calcasieu Project from $ ($ in net proceeds, after deducting net cash paid for natural gas) for the months ended , to $ ($ in net proceeds, after deducting net cash paid for natural gas) for the months ended .

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As a result, we have experienced, and expect to continue to experience during the remainder of the commissioning phase, significant volatility in the proceeds we have generated from the sales of commissioning cargos from the Calcasieu Project. Since we began generating proceeds from the sale of commissioning cargos in the first quarter of 2022, our quarterly gross proceeds have fluctuated from a maximum of $ billion ($ billion in net proceeds, after deducting net cash paid for natural gas) for the months ended , to a minimum of $ billion ($ billion in net proceeds, after deducting net cash paid for natural gas) for the three months ended . Accordingly, the proceeds we have generated from such sales of commissioning cargos of the Calcasieu Project to date may not be indicative of proceeds from such sales for any future period for the Calcasieu Project or for any of our other projects. 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 proceeds from the Calcasieu Project in the past, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

We have not entered into SPAs with customers for the total expected nameplate capacity at the CP2 Project, the CP3 Project or the Delta Project, 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, could have a material adverse effect on our prospects.

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. See “—Risks Relating to the LNG Industry—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 post-COD SPAs with us or otherwise contract with us, and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.”

We are actively marketing a portion of the remaining expected nameplate capacity of the CP2 Project to leading international oil and gas companies, national and multinational utilities and LNG portfolio trading companies. As of , 2024, the CP2 Project has contracted to sell mtpa of LNG under 20-year SPAs. The obligation to make LNG available under these post-COD SPAs commences from the occurrence of the relevant COD for each phase of the CP2 Project. As of this date, we have not entered into any SPAs for the expected nameplate capacity for the CP3 Project and the Delta Project and have not yet begun actively marketing the expected nameplate capacity for such projects. There can be no assurance that we will successfully negotiate binding SPAs with additional export customers with respect to an adequate portion of the expected nameplate capacity of the CP2 Project, the CP3 Project or the Delta Project or any other future projects to reach an FID with respect to such projects. At such projects, we may also choose to retain certain nameplate capacity on an uncontracted basis, while proceeding with construction activities, which would leave us more exposed to prevailing spot, short-, and medium-term prices during the life of the LNG facilities. To the extent we are unable to sell the expected nameplate capacity of any of our projects, 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 remaining LNG (such as pipeline transportation costs) without generating any corresponding revenue. If we are unable to enter into long-term contracts with customers for an adequate portion of the expected nameplate capacity at our future development projects, we may not be able to develop such project, raise adequate financing for such project, or realize sufficient cash flows for our business to remain profitable, which would have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

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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 are required under certain contracts to use our best efforts to construct and maintain LNG facilities capable of producing excess capacity at least equal to 15% of the guaranteed nameplate capacity of each facility. However, we also aim to construct and maintain our LNG facilities to be capable of producing greater excess capacity, in most cases at least 30% 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, prospects and the price of our Class A common stock. 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. See “—We have not entered into SPAs with customers for the total expected nameplate capacity at the CP2 Project, the CP3 Project or the Delta Project, 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, could have a material adverse effect on our prospects” for an example of historical volatility of the spot price for LNG and the resulting variability in our revenue.

To the extent we are unable to sell any such remaining 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 remaining LNG (such as pipeline transportation costs) 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, prospects and the price of our Class A common stock.

In addition, VG Commodities has contracted to resell at least 50% of the LNG generated by the Calcasieu Project in excess of its 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). In addition, we may enter into similar arrangements related to the excess LNG at our other projects in the future.

Our customers 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 under the circumstances described under “Business—Overview—Our Projects,” 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;

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•

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.

For example, we notified all of our customers under the Calcasieu Project post-COD SPAs of the anticipated delay to COD, indicating that such delay constitutes a force majeure event. As a result of such designation, the time period within which to achieve COD in such SPAs would be extended and such customers will not be entitled to terminate as a result of failure to designate COD until June 2025, at the earliest. All of such customers have questioned whether, and most have disputed in arbitration proceedings that, the delay constitutes a force majeure event, and they could assert that they are entitled to terminate their SPAs because COD did not occur by March 2024. 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 our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.”

In addition, the CP2 Foundation SPAs include termination rights in favor of the customer if certain conditions precedent are not satisfied by us or waived by the customer by a date certain in , including that we receive all LNG export authorizations by that date. Because of the temporary pause on new authorizations of natural gas exports to Non-FTA Nations described under “Business—Governmental Regulation—DOE Export Authorizations,” some of our customers under the CP2 Foundation SPAs may elect to terminate such SPAs. There can be no assurance that we will be able to secure any necessary extensions on similar terms with the remaining CP2 Foundation SPA customers or at all if the future deadlines are not met in the event of further delays or otherwise.

While we could potentially replace any terminated SPAs, 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) certain long-term SPAs for a particular project, and any breach of such requirement 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, prospects and the price of our Class A common stock.

We expect to have a limited number of customers to whom we sell LNG on a post-COD basis. For example, as of , 2024, we have executed mtpa of post-COD SPAs with customers with respect to LNG from our projects as described under “Business—Overview—Our Projects.” mtpa of such mtpa is contracted under 20-year fixed price SPAs and mtpa of such mtpa is contracted on a short- and medium-term basis. As of , 2024, approximately % of our revenue for the quarter then ended from individual external customers was concentrated across four customers. Moreover, as of , 2024, we had one customer which represented % 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

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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 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 severe adverse 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, prospects and the price of our Class A common stock.

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 facility charge 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.

We also anticipate that certain post-COD SPAs 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 our post-COD SPAs. At the same time, our operating expenses are likely to increase due to inflationary pressure. Any such increases may not be fully offset by any partial inflation adjustments under our post-COD SPAs 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, prospects and the price of our Class A common stock.

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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. As of , 2024, we have entered into several precedent and service agreements with interstate pipeline companies to provide the natural gas transportation to the Calcasieu Project and the Plaquemines Project. We have begun to contract for natural gas transportation requirements for the CP2 Project and are currently in negotiations with other gas transportation companies to provide further natural gas transportation requirements for the CP2 Project and the natural gas transportation requirements for the CP3 Project and the Delta Project. We will need to enter into and secure additional pipeline transportation capacity for the CP2 Project, the CP3 Project and the Delta Project for us to generate the expected nameplate and excess capacity of LNG at such projects. There can be no assurance that we will be able to enter into the requisite agreements to secure natural gas transportation capacity on terms acceptable to us, or at all, which would impair our ability to fulfill our obligations under any SPAs. Even if we have entered into the requisite agreements for our projects, there can be no assurance we will be able to secure the necessary natural gas transportation capacity for each of our projects.

In addition, we depend on third-party natural gas suppliers to provide the feed gas required to generate the expected nameplate and excess capacity of LNG at our projects. We anticipate that we will establish and maintain a portfolio of natural gas supply agreements or contracts to meet our requirements, which we have commenced for the Calcasieu Project and the Plaquemines Project, 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 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, prospects and the price of our Class A common stock. In addition, if we are unable to deliver any contracted volume in full, our customers will generally be entitled to reimbursement of costs and expenses for replacement LNG.

Total contracted revenue is based on certain assumptions and is presented for illustrative purposes only and actual sales under our SPAs may differ materially from such illustrative operating results.

We have included in this prospectus certain calculations of total contracted revenue as an illustrative metric reflecting revenue that could be generated under our post-COD SPAs as of a particular date for the remaining term of all such post-COD SPAs. These calculations are based on certain assumptions as described in the definition of “total contracted revenue” included under “Certain Important Terms.” Those assumptions include, among others, the development, completion and commissioning of each of the relevant projects (including obtaining any required regulatory approvals), estimated contracted volume for each project’s existing post-COD SPAs, assumed rate of inflation, and an assumed Henry Hub gas price per MMBtu. Such assumptions are based upon our management’s assessment of market comparables and other indicative pricing in the market and will be affected by various factors, including actual inflation rates and Henry Hub gas prices during the term of the relevant SPAs, performance by our customers under the applicable SPAs, as well as by the various risks and uncertainties relating to development, construction, commissioning and operation of each of our projects (including obtaining any required regulatory approvals) as described in this “Risk Factors” section. For example, actual inflation rates and actual Henry Hub gas prices during the term of the relevant SPAs will likely differ from the assumed rate of inflation and assumed Henry Hub gas price used in such calculation, and any such differences could be material. As a result, actual revenue generated under those SPAs will likely differ from the

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total contracted revenue included in this prospectus, and any such differences could be material. Investors should not place undue reliance on our illustrative calculations of the total contracted revenue.

We may not be successful in pursuing bolt-on expansion opportunities at our current 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 projects through bolt-on expansions that involve adding incremental liquefaction trains and certain related equipment to the relevant project. Our ability to pursue any such bolt-on expansion is subject to a number of risks and uncertainties and there can be no assurance that we will be able to complete all or some of our currently anticipated bolt-on expansion opportunities.

In particular, bolt-on expansion opportunities are subject to regulatory approval, and to date we have not made any filings with the necessary regulators, including DOE or FERC, with respect to any such expansion opportunities at our current projects. Such regulatory approvals are subject to numerous risks and uncertainties as described under “—Risks Relating to Regulation and Litigation,” and there can be no assurance that we will be successful in obtaining any such regulatory approvals. In addition, we aim to self-fund any bolt-on expansions using operating cash flows, and 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 projects. Further, any bolt-on expansion will require sufficient additional natural gas supply at the relevant project, and there can be no assurance we will be able to enter agreements for supply or transportation of the requisite natural gas on terms acceptable to us or at all.

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

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

Seasonal fluctuations will cause our business and results of operations to vary among quarters, which could adversely affect our business and results of operations, which could, in turn, negatively affect the price of our Class A common stock.

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 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, which could negatively affect the price of our Class A common stock.

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Substantially all of our anticipated revenue will be dependent upon our liquefaction 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 LNG industry, 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. See “Business—Our Business and Growth Strategies.” For example, we have acquired firm regasification facility capacity at the largest LNG regasification terminal in Europe, Grain LNG, in the United Kingdom, which we expect will allow us to import 42 LNG cargos per year beginning, depending on the starting period, anytime between October 1, 2029 to April 1, 2030, to and until July 14, 2045 (except for the period from April 1, 2030 to September 30, 2030 when only 13 LNG cargos can be imported). Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, beginning in 2025. Our capacity will account for approximately 25% of the total terminal capacity at Alexandroupolis, or approximately 12 cargos annually. 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 to secure additional regasification capacity in key import markets. See “—Risks Relating to Our Projects and Other Assets—Management and operation of our future LNG tanker fleet and the subcharter of third-party vessels will involve significant risks.”

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, prospects and the price of our Class A common stock. Integration of an acquired company also may disrupt ongoing operations and require management 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, prospects and the price of our Class A common stock.

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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 liquefaction 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 coastal operations.

We will be 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 insurance coverage in respect of the Calcasieu Project, the Plaquemines Project, and with respect to third-party liability coverage, the CP2 Project, and standard hull and machinery insurance and protection and indemnity insurance for 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 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. 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, prospects and the price of our Class A common stock.

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 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 Hurricane Laura in August 2020, Hurricane Delta in October 2020, Hurricane

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Ida in August 2021, and Hurricane Ian in September 2022. 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, prospects and the price of our Class A common stock.

Furthermore, the Calcasieu Project and the Plaquemines Project each maintain a Named Windstorm Insurance Program, which is structured as a layered program with a limit of $250 million at each location, with VGLNG Insurance, LLC, or VGLNG Insurance, one of our subsidiaries. See “Business—Insurance—Named Windstorm Insurance (NWS).”

The use of captive insurance entities necessarily involves retaining certain risks that might otherwise be covered by traditional insurance products.

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, which in turn could have a material adverse effect on the price of our Class A common stock.

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, 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, prospects and the price of our Class A common stock.

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 if we expand requires, among other things:

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continued development of financial and management systems;

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implementation of adequate internal control over financial reporting and disclosure controls and procedures;

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•

hiring and training of new personnel; and

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coordination among logistical, technical, accounting, finance, information technology, administrative, and commercial personnel.

An inability to manage successfully any of these factors could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity, financing requirements, prospects, and the price of our Class A common stock.

We are dependent on the strategic direction of Michael Sabel, our Chief Executive Officer, Executive Co-Chairman and Founder, and Robert Pender, our Executive Co-Chairman, Director and Executive Co-Chairman of the Board and Founder.

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, prospects and the price of our Class A common stock.

Before construction of any project begins, we and our contractors, including our EPC contractors, need to hire new on-site employees to manage the construction of each project. We have engaged an EPC contractor to meet some of the construction labor needs of the Plaquemines Project and Phase 1 of the CP2 Project and we plan to engage EPC contractors to meet some of the construction labor needs of Phase 2 of the CP2 Project, the CP3 Project, the Delta Project, and any future projects we develop. 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, prospects and the price of our Class A common stock.

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 been experiencing recently and may 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, prospects and the price of our Class A common stock.

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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. 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 greater scrutiny by the state, and have been subjected to a greater burden 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.

Our ability to use our net operating losses to offset future taxable income may be subject to certain limitations.

As of December 31, 2023, we have accumulated federal net operating loss, or NOL, carryforwards of $367 million with an indefinite carryforward period. We additionally had accumulated state net operating loss carryforwards of approximately $1.7 billion (after the application of state apportionment factors), 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, $42 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, including as a result of this offering or future changes, and some of which may be outside of our control, 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.

Risks Relating to Our Projects and Other Assets

We are in the process of commissioning the Calcasieu Project, constructing the Plaquemines Project and developing the CP2 Project, the CP3 Project and the Delta Project. An amount expected to be necessary to complete the Calcasieu Project and achieve COD for the Calcasieu Project is held in cash reserve accounts pursuant to our project financing arrangements and reflected as restricted in our financial statements. While we

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believe we have sufficient project-level cash, borrowing capacity under our existing project-level debt financing, and access to substantial commissioning cargo proceeds to fund the completion of the Plaquemines Project based on our current estimate of the total project costs, the CP2 Project, the CP3 Project and the Delta Project, as well as any future projects we develop, will require significant additional funding.

As of , 2024, we estimate that the total project costs for the Plaquemines Project will be approximately $ , including EPC contractor profit and contingency, owners’ costs and financing costs, of which approximately $ had been paid for as of , 2024. As of , 2024, we have additional available borrowing capacity of $ under the Plaquemines Credit Facilities. In addition, as of , 2024, we estimate that the total project cost for the CP2 Project, the CP3 Project and the Delta Project will range from approximately $ to $ , $ to $ and $ to $ , respectively, in each case including EPC contractor profit and contingency, owners’ costs and financing costs, substantially all of which have not yet been funded. 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 Phase 1 EPC Contract, and reflect the current inflationary environment as well as the fact that the pipelines for the CP2 Project, the CP3 Project and the Delta Project are expected to be longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. The CP3 Project and the Delta Project are also expected to be larger in scale than our first three projects, with expected nameplate capacity of 30.0 mtpa and 24.4 mtpa, respectively.

Moreover, no substantial construction work has been undertaken on either the CP3 Project or the Delta Project to date, we have not yet entered into a number of material contracts (including an EPC contract for Phase 2 of the CP2 Project, or any portion of the CP3 Project or the Delta Project) for the CP2 Project, the CP3 Project or the Delta Project, and our actual costs could vary significantly from our preliminary estimates 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 the CP2 Project, the CP3 Project, the Delta Project, or any other natural gas liquefaction and export facility we may decide to develop in the future, on the same or substantially similar terms as the Calcasieu EPC Contract, the Plaquemines EPC Contracts or the CP2 Phase 1 EPC Contract. As a result, our cost estimates are only an approximation of the actual costs of construction and financing for the CP2 Project, the CP3 Project and the Delta Project. Our actual project costs may be higher, potentially materially, compared to our current estimates as a result of many factors as described 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 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. 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, and, based upon current estimates, the Plaquemines 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 financing transactions, mezzanine financing and/or other similar financing alternatives). 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 the CP2 Project, the CP3 Project or the Delta Project. 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 CP3 Project, the Delta

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Project or any future project we may develop will be similar to those used for the Calcasieu Project and Plaquemines Project.

Additional capital may not be available in the amounts required, on favorable terms, or at all, and is subject to the risks described under “—Risks Relating to Our Indebtedness and Financing—Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred units of our subsidiaries also give the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities.” 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 or 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. See “—Risks Relating to the LNG Industry—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 and the price of our Class A common stock” and “—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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 have experienced unexpected delays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, we expect COD for the Calcasieu Project to be delayed while significant work related to commissioning, carryover completions, rectification, and certain other items is being completed, and we are currently targeting a COD for the Calcasieu Project in . Further, while we are generating commissioning cargo proceeds at the Calcasieu Project and plan to also 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, which could also require us to obtain additional sources of capital to fund development, construction and commissioning of our projects. See “—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. 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 proceeds for any future period or for any of our other 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 commercial

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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, prospects and the price of our Class A common stock.

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. 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. 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.

When completed, our natural gas liquefaction and export projects, including the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project, and any future projects we develop, may face significant operational risks.

As more fully discussed in these “Risk Factors,” the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project and the Delta Project and any other natural gas liquefaction and export facilities that we may decide to develop in the future involve operational risks, including the following:

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explosions, pollution, releases of toxic substances;

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the facilities performing below expected levels of efficiency;

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breakdown or failures of equipment;

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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;

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operational errors by vessel or tug operators;

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operational errors by us or any contracted facility operator;

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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, prospects and the price of our Class A common stock.

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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.

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 dates of the Calcasieu Project or the Plaquemines Project are delayed beyond an agreed date certain for each project, an event of default under the Calcasieu Pass Credit Facilities, the VGCP Senior Secured Notes and the Plaquemines Credit Facilities 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 Calcasieu Project or Phase 1 or 2 of the Plaquemines Project beyond a certain deadline could also result in an event of default under the Calcasieu Pass Credit Facilities or the Plaquemines Credit Facilities, respectively, and/or certain investors exercising step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project” and “—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, prospects and the price of our Class A common stock.”

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:

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maintain its own financial condition, including adequate working capital, and its ability to pay debt service and other liabilities;

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accurately estimate certain costs, including material, construction and fabrication costs, from third parties such as suppliers and subcontractors;

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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;

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design, engineer and build the facilities constituting the projects to operate in accordance with specifications and on schedule;

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engage and retain third-party subcontractors and procure equipment and supplies;

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attract, develop and retain skilled personnel, including engineers, and address any labor issues that may arise;

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respond to market conditions in the construction industry, including recent shortages of personnel and recent increases in operating costs;

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address any start-up and operational issues that may arise in connection with the commencement of commercial operations;

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post and maintain required construction bonds or other performance assurance and comply with the terms thereof; and

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manage the construction process generally, including coordinating with other contractors, third-party contractors and regulatory agencies.

Although agreements with our contractors may provide for liquidated damages 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 liquidated damages 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 liquidated damages. For example, we have had disagreements with Kiewit, our EPC contractor for the Calcasieu Project. Kiewit disputed our withholdings under the Calcasieu EPC Contract, asserting that our withholdings amount to a breach of our payment obligations (including the payment of appropriate profit margin payable to Kiewit), and also asserted that it is entitled to a portion of certain net LNG sales proceeds earned by the Calcasieu Project. That dispute was submitted to arbitration, and in February 2024 the arbitration tribunal issued an award in respect of the first phase of the arbitration in favor of Kiewit of approximately $158 million. The second phase of the arbitration is ongoing.

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

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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.

For example, the Plaquemines Project is being constructed pursuant to two integrated turn-key EPC contracts, one per phase, or the Plaquemines EPC Contracts, that we entered into with KZJV, LLC, or KZJV, a limited liability company that is owned by Kellogg Brown & Root LLC, or KBR EPC Member, and Zachry Industrial, Inc., or Zachry Industrial. In May 2024, Zachry Industrial, along with Zachry Holdings, Inc., or Zachry Holdings, one of the parent guarantors under the Plaquemines EPC Contracts for the Plaquemines Project, and certain of their affiliates filed for bankruptcy protection under Chapter 11 of the U.S. bankruptcy code, or the Zachry Bankruptcy. Although it is our understanding that KZJV, Zachry Industrial, and KBR EPC Member are committed to avoiding any disruption to the Plaquemines Project, there can be no assurance that the Zachry Bankruptcy will not have a material adverse impact on the project. In particular, the bankruptcy court could authorize Zachry Industrial and/or Zachry Holdings to take various actions that could adversely impact KZJV, the Plaquemines Project, the Plaquemines EPC Contracts and the related parent guarantees, including rejecting or otherwise impairing Zachry Holdings’ parent guarantee, seeking to sell or otherwise monetize Zachry Industrial’s interest in KZJV, or otherwise rejecting any contractual obligations of Zachry Holdings and its affiliates in connection with the Plaquemines EPC Contracts. In addition, the Zachry Bankruptcy may result in the exercise of any applicable termination or step-in rights in connection with the KZJV limited liability company agreement and any related arrangements as well as disputes between KBR EPC Member and Zachry Industrial, or their parent guarantors, with respect to the KZJV joint venture and their respective obligations in connection with the Plaquemines EPC Contracts, which may adversely impact KZJV’s, its members’ or its parent guarantors’ willingness or ability to perform their respective contractual obligations in connection with the Plaquemines EPC Contracts and related parent guarantees. Such events may also constitute an event of default under the Plaquemines EPC Contracts. If KZJV is unable or unwilling to perform according to the negotiated terms and timetable of the Plaquemines EPC Contracts, we may decide to engage a substitute EPC contractor, which could result in material cost increases and/or delays in the ability of both phases of the Plaquemines Project to achieve commercial operations. There also can be no assurance that we would be able to enter into an EPC contract with any such substitute EPC contractor on similar terms, or at all. Further, the Zachry Bankruptcy resulted in an event of default under the related project financing for the Plaquemines Project. While the relevant lenders have waived such event of default, there can be no assurance they would waive any further events of default that occur in the future, and the occurrence of any such further event of default, if not waived, would allow the lenders to accelerate such project financing and foreclose on the collateral securing such financing. Any of the foregoing could result in material delays or termination of the Plaquemines Project, and could have a material adverse impact on our ability to complete the Plaquemines Project on our anticipated schedule and budget, or at all. In addition, if we are not able to recover under the Zachry Holdings parent guarantee, we may not be able to recover in full any damages or other amounts we are entitled to under the Plaquemines EPC Contracts even though the KBR, Inc. and Zachry Holdings parent guarantees provide for joint and several liability.

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, prospects and the price of our Class A common stock.

We have not entered into all of the definitive agreements for the CP2 Project, the CP3 Project or the Delta Project, 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 the CP2 Project, other than purchase orders for liquefaction systems and power island systems with Baker Hughes Energy Services LLC (formerly known as GE

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

Oil & Gas, LLC), or Baker Hughes, for Phase 1 of the CP2 Project, the CP2 Phase 1 EPC Contract, and an EPC contract for the LNG storage tanks with CB&I for Phase 1 of the CP2 Project, and the Baker Hughes Master Agreement, which provides for the potential supply of liquefaction trains and power islands that could be utilized for Phase 2 of the CP2 Project. In addition, we have not entered into any of the necessary definitive agreements with the key suppliers and contractors necessary for the development and construction of the CP3 Project and the Delta Project other than the Baker Hughes Master Agreement. We may not be able to successfully negotiate such contracts for the CP2 Project, the CP3 Project or the Delta Project, or other projects we may develop in the future, on terms or at prices that are acceptable to us. Our inability to negotiate and execute definitive agreements with such contractors on terms acceptable to us could have a material adverse impact on our ability to complete the CP2 Project, the CP3 Project or the Delta Project, and any projects we may develop in the future, on our anticipated schedule and budget, or at all.

In particular, we have not yet entered into an EPC contract for Phase 2 of the CP2 Project, the CP3 Project or the Delta Project, and there can be no assurance that we will be able to do so on a timely basis or at all. If we are unable to negotiate an EPC contract for Phase 2 of the CP2 Project, the CP3 Project or the Delta Project on a timely basis and on terms that are acceptable to us or that are similar to the terms in the Calcasieu EPC Contract, the Plaquemines EPC Contracts and the CP2 Phase 1 EPC Contract, the development and construction of Phase 2 of the CP2 Project, the CP3 Project or the Delta Project may be delayed or they may not be built at all, and the construction cost of the CP2 Project, the CP3 Project or the Delta Project 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, prospects and the price of our Class A common stock.

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 purchase orders for the liquefaction systems and power island systems for Phase 1 of the CP2 Project, we have not yet executed any such purchase orders for Phase 2 of the CP2 Project, the CP3 Project or the Delta Project. 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 remaining purchase orders for Phase 2 of the CP2 Project, the purchase orders for the CP3 Project, and the purchase orders for the Delta Project 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 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.

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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, the CP3 Project or the Delta Project 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) unexpected delays in construction or commissioning, and (viii) unexpected repair, replacement, rectification, or warranty work. 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 estimated costs for any potential bolt-on expansion opportunities that we may pursue in the future. 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.

We expect that the remaining project costs to achieve COD for the Calcasieu Project will be funded with cash we hold in reserve accounts pursuant to our project financing arrangements, which is reflected as restricted cash in our financial statements. However, there is no assurance as to whether the amount of cash held in these accounts will be sufficient to complete the construction of the Calcasieu Project and achieve COD, including, for example as a result of any additional unforeseen costs related to ongoing repairs and replacements or an unsuccessful outcome of any of our pending legal proceedings. 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 our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.”

As of , 2024, we estimate that the total project costs for the Plaquemines Project will be approximately $ , including EPC contractor profit and contingency, owners’ costs and financing costs, of which approximately $ had been paid for as of , 2024. 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 December 2023, VGLNG has made several incremental equity contributions to VGPL in an aggregate amount equal to $ to address such increases in estimated total project costs. Pursuant to the Plaquemines Credit Facilities, if such contributions have been utilized to pay project costs 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. Such reimbursements may be possible if (i) VGPL has received

incremental funds (including commissioning cargo proceeds) to cover any such project cost increases or (ii) the

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

budget otherwise decreases due to cost savings. 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 exceed our current contingency, and any such additional contributions or funding could be significant.

As of , 2024, we estimate that the total project costs for the CP2 Project, the CP3 Project and the Delta Project will range from approximately $ to $ , $ to $ and $ to $ , respectively, in each case including EPC contractor profit and contingency, owners’ costs and financing costs, substantially all of which have not yet been funded. These estimates are based primarily upon our construction cost experiences with the Calcasieu Project and the Plaquemines Project, the pricing included in the CP2 Phase 1 EPC Contract, and reflect the current inflationary environment as well as the fact that the pipelines for the CP2 Project, the CP3 Project and the Delta Project are expected to be longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. The CP3 and Delta projects are also expected to be larger in scale than our first three projects, with expected nameplate capacity of 30.0 mtpa and 24.4 mtpa, respectively. Moreover, no substantial construction work has been undertaken on either the CP3 Project or the Delta Project to date, we have not yet entered into a number of material contracts (including an EPC contract for Phase 2 of the CP2 Project, or any portion of the CP3 Project or the Delta Project) for the CP2 Project, the CP3 Project or the Delta Project, and our actual costs could vary significantly from our preliminary estimates 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 the CP2 Project, the CP3 Project, the Delta Project, or any other natural gas liquefaction and export facility we may decide to develop in the future, on the same or substantially similar terms as the Calcasieu EPC Contract, the Plaquemines EPC Contracts or the CP2 Phase 1 EPC Contract. As a result, our cost estimates are only an approximation of the actual costs of construction and financing for the CP2 Project, the CP3 Project and the Delta Project.

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, prospects and the price of our Class A common stock. See also “—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 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. 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, prospects and the price of our Class A common stock.

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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 receipt and maintenance of required regulatory approvals and permits and upon various activities being completed by our contractors. See “—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” and “—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.” Any significant construction or commissioning delay 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, prospects and the price of our Class A common stock.

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 have experienced unexpected delays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, we expect COD for the Calcasieu Project to be later than originally forecasted while significant work related to commissioning, carryover completions, rectification, and certain other items is being completed. Although we are currently generating revenue from sales of LNG commissioning cargos from the Calcasieu 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, based on a cross-default, 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 foreclose against all collateral that secures such debt, representing substantially all assets of the relevant project, which could seriously harm our business and lead to a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock. 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 Calcasieu Project or Phase 1 or 2 of the Plaquemines Project beyond a certain deadline could also result in an event of default under the Calcasieu Pass Credit Facilities or the Plaquemines Credit Facilities, respectively, and/or certain investors exercising step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project.”

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 and/or from post-COD SPAs or lead to a loss of one or more customers in the event of significant delays. In particular, 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. 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 our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.”

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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 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:

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maintain their own financial condition, including adequate working capital, and their ability to pay debt service and other liabilities;

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accurately estimate certain costs;

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meet quality or performance standards for third party equipment;

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procure equipment and supplies;

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execute requisite work and services efficiently; and

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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, prospects and the price of our Class A common stock.

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 early 2022) 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 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:

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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;

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our ability to enter into final ground leases for the relevant project site;

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the identification of any adverse issues with respect to the relevant project site;

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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;

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our ability to administer the Calcasieu EPC Contract, the Plaquemines EPC Contracts, and the CP2 Phase 1 EPC Contract and to successfully negotiate a definitive agreement with EPC contractors for Phase 2 of the CP2 Project, the CP3 Project, the Delta Project and any future projects 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;

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our ability to secure definitive post-COD SPAs for an adequate portion of the expected nameplate capacity of the CP2 Project, the CP3 Project, the Delta Project or any future projects we develop to support an FID for each such project;

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

our ability to secure necessary additional capital or financing on satisfactory terms, or at all, to develop the CP3 Project and the Delta Project and any additional projects;

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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;

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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;

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force majeure events, natural or man-made disasters, terrorist attacks or sabotage;

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shortages of materials or delays in the delivery of materials;

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weather conditions and impacts from potential climate change, hurricanes, severe weather events and other catastrophes, such as explosions, fires, floods and accidents;

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local and general economic and infrastructure conditions;

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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;

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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;

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economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

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decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects; and

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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. For example, in a December 11, 2023 letter to the DOE, a coalition of more than 200 environmental groups called on the DOE to deny the export license for Non-FTA Nations for the CP2 Project on the alleged basis that it is not in the public interest. In January 2024, the Biden administration announced a temporary pause on new authorizations of natural gas exports to non-FTA Nations while the DOE conducts studies to update its analyses regarding whether the exports are “not inconsistent with the public interest.” See “—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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. 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. Notably, project opponents are challenging FERC’s recent authorization for the CP2 Project in an appeal filed with the U.S. Court of Appeals for the D.C. Circuit. While that Court has historically respected FERC’s authorizations on appeal, earlier this year it granted in part challenges to the FERC approvals for certain other LNG export and natural gas pipeline projects.

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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. 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, prospects and the price of our Class A common stock.”

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, prospects and the price of our Class A common stock. See also “—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” and “—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors.”

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 CP2 Project, the CP3 Project and the Delta Project, 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. At their expected peak production capacity, we expect these three development stage projects will require approximately 4.3, 6.5 and 5.3 bcf/d of gas supply, respectively. We plan to construct significant 48 inch 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. See “Business—Key, Complementary Assets—Natural Gas Supply and Transportation.”

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 and the Gator Express Pipeline route for the Plaquemines 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.

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As a result of these factors, our pipeline infrastructure for the CP2 Project, the CP3 Project and the Delta Project 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 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 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, the CP3 Project, the Delta Project, and any other natural gas liquefaction and export facilities (including any expansion of existing facilities) 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 the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project or any future natural gas liquefaction and export facilities we may decide to develop 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, prospects and the price of our Class A common stock 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 liquefaction projects, except for the Calcasieu Project and the Plaquemines Project. As a result,

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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, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock. 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.

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, 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 the Plaquemines Project or any other project. 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, prospects and the price of our Class A common stock.

The phased commissioning start-up of our projects will subject us to additional risks.

The unique configuration of our liquefaction 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 plan to begin the commissioning start-up of the relevant equipment on a phased basis. This sequential commissioning of the liquefaction blocks, 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, 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 any 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, prospects and the price of our Class A common stock.

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

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and performance capabilities that we intend, the estimates set forth in this prospectus 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, prospects and the price of our Class A common stock. Further, we will not generate any revenues or cash flows under our post-COD SPAs (including the Calcasieu Foundation 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, 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, based on a cross-default, 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, prospects and the price of our Class A common stock.”

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, prospects and the price of our Class A common stock.

We have completed the construction of only one of our natural gas pipeline projects, the TransCameron Pipeline. One of our other pipelines, the Gator Express Pipeline, is nearly complete after achieving mechanical completion in October 2023, introducing natural gas for commissioning activities in April 2024, and placing a portion of the pipeline connecting the LNG terminal to Texas Eastern Transmission in service in May 2024, and we aim to place the second lateral of the Gator Express Pipeline in service in , 2024. Construction and operations of our future, planned natural gas pipelines and pipeline connections for our projects, including the CP Express natural gas pipeline, the pipeline required for the CP3 project and the Delta Express natural gas pipeline, 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:

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failure to obtain and maintain relevant approvals and permits from governmental and regulatory agencies;

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difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;

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difficulties in engaging qualified contractors necessary for the construction of natural gas pipelines and lateral pipeline connections for any of our projects;

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shortages of equipment, material or skilled labor;

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natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents and terrorism;

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unscheduled delays in the delivery of ordered materials;

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EPC productivity factor realization, work stoppages and labor disputes;

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difficulties or delays in obtaining, or failure to obtain, sufficient real property interests on which to construct and locate the pipelines and associated facilities;

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unexpected or unanticipated need for additional improvements;

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unexpected additional material quantities and labor hours; and

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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, prospects and the price of our Class A common stock.

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, prospects and the price of our Class A common stock.

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 20-year transportation arrangements, including agreements with Texas Eastern Transmission LP, ANR Pipeline Company, Sabine, Columbia Gulf, and Tennessee Gas Pipeline. We are also in the process of contracting for, or developing, the required transportation capacity for our other projects. We do not have any control over the operation, development, expansion or maintenance of these pipelines or certain other third-party pipeline and 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. 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. 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.

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Delays in deliveries of newbuild or acquired 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 would delay or eliminate our ability to optimize contracts with spot and term DPU customers. The relevant shipbuilder or third-party seller could fail to deliver the newbuild LNG tankers or the relevant shipbuilding contract or acquisition agreement could be cancelled if the shipbuilder, the seller or we have not met certain obligations, including the failure to pay any remaining amounts required under such agreements. In addition, third-parties from whom we may charter LNG tankers may fail to deliver such LNG tankers to us, or such deliveries could be delayed. If delivery of any newbuild LNG tankers currently contracted to be acquired, or any LNG tanker we contract to charter on a third-party basis, or acquire or charter in the future, is materially delayed, it could adversely impact our business and we may not be able to realize the anticipated benefits of operating our LNG tanker fleet.

Our receipt of newbuilds could be delayed, cancelled or otherwise not completed because of, among other things, quality or engineering problems or failure to deliver the LNG tanker in accordance with the specifications, changes in governmental regulations or maritime self-regulatory organization standards, delays to delivery of equipment by third-party suppliers, work stoppages or other labor disturbances at the shipyard, bankruptcy or other financial or liquidity problems of the shipbuilder, a backlog of orders at the shipyard, political or economic disturbances in the country or region where the vessel is being built, weather interference or catastrophic events, shortages of or delays in the receipt of necessary construction materials, such as steel, and our inability to finance the purchase of the LNG tanker.

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.

Additionally, the final cost of the LNG tankers we have contracted to acquire could increase, pursuant to adjustment provisions included in the respective contracts. As of , 2024, an aggregate of approximately $ remains payable pursuant to our existing contracts to acquire the LNG tankers. We may decide to raise additional capital to fund our remaining payment commitments pursuant to such contracts. Our ability to obtain financing that may be used to provide additional funding to cover all of the costs for our LNG tankers will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all, which could impact our ability to make payments under our contracts to acquire LNG tankers when due. Any failure to make payments under any existing or future contracts to acquire LNG tankers could cause delays in the delivery of our newbuild LNG tankers or could result in an event of default under our contracts for the acquisition of LNG tankers. In addition, if we are unable to make any payments under our existing contracts to acquire LNG tankers when due, we may lose our rights to acquire such LNG tankers as well as our right to be refunded certain amounts already paid pursuant to the applicable contracts.

Delays in the delivery, or shortfalls in the construction and acquisition of, our LNG tanker fleet, could require us to charter or subcharter 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, prospects and the price of our Class A common stock. See “—Management and operation of our future LNG tanker fleet and the subcharter of third-party vessels will involve significant risks.”

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Management and operation of our future LNG tanker fleet and the subcharter of third-party vessels will involve significant risks.

Through certain wholly-owned subsidiaries, we have entered into contracts to acquire nine LNG tankers that are currently under construction and will be delivered on a rolling basis beginning in 2024 through 2026, which will be used to provide additional optionality to spot and term customers and to service our single existing post-COD DPU SPA and any future DPU SPAs. 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 are in the process of building out our team to manage and operate our fleet of LNG tankers, and as a result we will be exposed to various new operational risks as we expand that team and grow our fleet of LNG tankers. We will also be exposed to operational risks where we subcharter third-party vessels. For example, we will be exposed to the following risks with respect to the operation of LNG tankers:

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the Company’s limited track record with managing and operating our own LNG tanker fleet;

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performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

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breakdowns or failures of equipment or shortages or delays in the delivery of supplies;

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risks related to operators and service providers of tanker or tugs used in our operations;

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operational errors by us or any contracted facility, port or other operator of related infrastructure.

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failure to maintain the required government or regulatory approvals, permits or other authorizations;

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accidents, fires, explosions or other events or catastrophes;

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a lack of adequate and qualified personnel to adequately crew and operate the LNG tankers;

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potential labor shortages, work stoppages or labor union disputes;

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our potential inability to recruit and retain a team to manage and operate our fleet of LNG tankers and any subchartered third-party vessels;

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weather-related or natural disaster interruptions of operations;

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pollution, release of or exposure to toxic substances or environmental contamination, including marine accidents and spills, affecting operations;

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inability, or failure, of any counterparty to any fleet-related agreements to perform their contractual obligations;

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a lack of demand for shipping services by our customers after we receive delivery of our LNG tankers or subcharter a third-party vessel;

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failures to supply due to scheduled or unscheduled maintenance; and

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potential changes to cabotage laws which may affect the ability of our LNG tankers and subchartered third-party vessels to engage in coastwise trade.

As a result, in addition to our current operational risks, we will be subject to risks related to the operation of LNG tankers, which operations 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 subchartered 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.

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If our LNG tankers, or any vessels we subcharter, suffer damage 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 capital expenditures. The loss of earnings or costs to subcharter 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, prospects and the price of our Class A common stock.

If one of our LNG tankers, or any vessels we subcharter, 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, prospects and the price of our Class A common stock. 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, building or maintaining our LNG tanker fleet, we may be required to subcharter vessels from third parties. Additionally, our ability to subcharter vessels from third parties could be affected by potential shortages of LNG tankers worldwide. See “—Risks Related 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, prospects and the price of our Class A common stock.” As the overall trends steer toward more regulation and more stringent operating requirements, we are subject to the risk that subchartered 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, prospects and the price of our Class A common stock.

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:

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explosions, pollution, releases of toxic substances;

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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;

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breakdown, failures or mechanical issues affecting our equipment;

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operational errors by vessel or tug operators;

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operational errors by us or any contracted facility operator; and

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labor disputes.

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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, prospects and the price of our Class A common stock.

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 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 successfully against 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 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. See “Business—Competition.”

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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, prospects and the price of our Class A common stock. 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:

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increases in worldwide LNG production capacity and availability of LNG for market supply;

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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 current price equilibrium with respect to supply;

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increases in the cost to supply natural gas feedstock to our projects (see “—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 and the price of our Class A common stock.”);

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decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

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decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

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increases in capacity and utilization of nuclear power, renewable power, and related facilities outside the United States;

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political instability in foreign countries that import LNG, or strained relations between such countries and the United States; and

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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.

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 post-COD SPAs with us or otherwise contract with us, and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

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, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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 facility charge 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 post-COD SPAs with us 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, prospects and the price of our Class A common stock.

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 and the price of our Class A common stock.

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 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:

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competitive liquefaction capacity in North America;

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insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

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insufficient LNG tanker capacity;

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weather conditions, including temperature volatility resulting from changes in climate, and severe weather events may lead to unexpected distortion in the balance of international LNG supply and demand;

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reduced demand and lower prices for natural gas;

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the extent of domestic production and importation of natural gas in relevant markets;

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increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

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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;

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cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;

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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;

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changes in regulatory, tax, environmental or other governmental policies 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;

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political conditions in natural gas producing regions, including geopolitical events such as the Russia-Ukraine conflict and the conflicts occurring in the Middle East;

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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;

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adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and

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cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

For example, significant price fluctuations for natural gas could materially affect the value of our inventory, as well as the linefill and tank bottoms that we account for as non-current assets. 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 adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

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, prospects and the price of our Class A common stock.

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:

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an inadequate number of shipyards constructing LNG tankers and a backlog of orders at these shipyards;

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political or economic disturbances in the countries where the vessels are being constructed;

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acts of war or piracy;

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changes in governmental regulations or maritime self-regulatory organizations;

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work stoppages or other labor disturbances at the shipyards;

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bankruptcy or other financial crisis of shipbuilders or shipowners;

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quality or engineering problems;

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disruptions to maritime transportation routes;

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weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and

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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, prospects and the price of our Class A common stock.

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, prospects and the price of our Class A common stock.

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.

As of , 2024, our subsidiaries had approximately $ in outstanding debt, which consisted of $ of debt incurred by VGLNG and approximately $ in project-level debt financing. In addition, our project-level equity investment subsidiaries for the Calcasieu Project, Calcasieu Holdings and Calcasieu Funding, issued preferred units for total gross proceeds of $ , with an aggregate liquidation preference of approximately $ as of , 2024, some of which require us to make preferential cash distributions to the holders under certain circumstances. See “Description of Indebtedness and Project Financing.” As of , 2024, we also had approximately $ of additional borrowing capacity under our existing financing agreements. This substantial amount of indebtedness and preferred equity could have important consequences to us, including:

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making it more difficult for us to satisfy our obligations with respect to our existing debt and our subsidiaries’ existing preferred equity;

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limiting our ability, or increasing the costs, to refinance our indebtedness;

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limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy or other purposes;

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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;

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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;

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limiting our ability to react to changing market conditions in our industry, to our customers’ businesses and to economic downturns;

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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;

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limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;

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limiting our ability to capitalize on business opportunities and to react to competitive pressures; and

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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.

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 on preferred units of our subsidiaries. Such payments may reduce the funds available to us to construct and complete the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project or any 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 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. To date, we do not have any material sales, operating cash flow or operating history, other than the short-term sales of LNG commissioning cargos from the Calcasieu Project prior to commencing commercial operations, and we cannot assure you when we will begin to generate any operating cash flow from commercial operations. 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

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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 foreclose against 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 (as described in “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Funding, LLC Preferred Units”) 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, and the price of our Class A common stock.

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. In particular, our subsidiaries may incur additional indebtedness that may restrict or prohibit the making of distributions, the paying of dividends or the making of loans by such subsidiaries to the Company. See “—Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred units of our subsidiaries also give the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities.” In addition, such payments may be limited as a result of claims against 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, and the price of our Class A common stock.

Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred units of our subsidiaries also give the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities.

The Calcasieu Pass Credit Facilities, the Plaquemines Credit Facilities and the indentures governing the VGCP Senior Secured Notes contain various covenants restricting the ability of certain of our subsidiaries to, among other things:

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incur or guarantee additional debt or issue disqualified stock or preferred stock;

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pay dividends (including to the Company) and make other distributions on, or redeem or repurchase, capital stock;

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make certain investments;

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incur certain liens;

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enter into transactions with affiliates;

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merge or consolidate;

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enter into agreements that restrict the ability of restricted subsidiaries to make dividends or other payments to the issuers;

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designate restricted subsidiaries as unrestricted subsidiaries; and

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transfer or sell assets.

In addition, the credit agreement governing the Calcasieu Pass Credit Facilities requires VGCP to maintain a historical debt service coverage ratio of 1.15:1 for the 12-month period ending as of the end of any fiscal quarter. Analogous requirements apply to VGPL under the Plaquemines Credit Facilities when certain milestones are met.

The holders of preferred units of Calcasieu Holdings (or Class B common units after they are converted according to their terms) 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:

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amending key project contracts;

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incurring any additional indebtedness in excess of $75.0 million, subject to certain exceptions; and

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issuing or redeeming equity under certain circumstances.

In addition, other than Calcasieu Holdings 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 indentures governing the VGLNG Senior Secured Notes contain various covenants restricting the ability of certain of our subsidiaries to, among other things:

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incur or guarantee additional indebtedness or issue disqualified stock or certain preferred stock;

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pay dividends and make other distributions or repurchase stock;

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create or incur certain liens; and

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merge, consolidate or transfer or sell all or substantially all of their assets.

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.

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.

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Our common equity interest in the Calcasieu Project will be diluted if we are unable to, or elect not to, pay certain distributions on the Holdings Preferred Units in cash.

As of , 2024, a third-party investor currently holds preferred units, or Holdings Preferred Units, of Calcasieu Holdings, which is an indirect parent entity of the Calcasieu Project. We have the option to pay the distributions on the Holdings Preferred Units either in kind in the form of issuing additional Holdings Preferred Units, or Holdings PIK Units, or in cash. See “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Holdings, LLC Preferred Units.” Upon COD at the Calcasieu Project, Holdings Preferred Units, including any Holdings PIK Units outstanding, will automatically convert into Class B common units of Calcasieu Holdings, or Class B Common Units. Assuming that COD occurs in and that we service all future distributions on the Holdings Preferred Units until the commencement of COD in cash, we expect the Holdings Preferred Units to convert into a number of Class B Common Units, equal to approximately % of the total outstanding common units of Calcasieu Holdings, or Holdings Common Units, reducing our common equity interest in the Calcasieu Project to approximately %. However, if we are unable to, or elect not to, make payments on the Holdings PIK Units in cash, our common equity interest in the Calcasieu Project could be further diluted. While we expect to continue making distributions on the Holdings Preferred Units in cash, this is based on certain assumptions which could be affected by a number of factors beyond our control. In addition, we may enter into similar equity financing arrangements in the future with respect to our other projects. Greater dilution of our common equity interest in the Calcasieu Project or any other project would decrease our control over the Calcasieu Project (or such other project) and the amount of cash distributions that we receive from the Calcasieu Project (or such other project), which may have a material adverse effect on our business, financial condition, cash flows and results of operations, and the price of our Class A common stock.

Increases in interest rates would increase the cost of servicing our debt and could reduce our profitability.

The debt outstanding under the Calcasieu Pass Credit Facilities and the Plaquemines 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, which would negatively impact the price of our Class A common stock.

The U.S. Federal Reserve Board has significantly increased the federal funds rate in 2022 and 2023 and it could maintain rates at historically high levels to combat inflation in the United States for longer than expected, which has increased the borrowing costs on our variable rate debt and may keep the cost of any new debt we incur at such increased levels. 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, the CP3 Project, the Delta Project and any other natural gas liquefaction and export facilities, or other projects, that we may decide to develop in the future. As of , 2024, our subsidiaries would have had approximately of

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additional borrowing capacity in the form of available commitments as of , 2024, comprised of approximately $ of construction term loans under the Plaquemines Credit Facilities, approximately $ of working capital loans under the Plaquemines Working Capital Facility (after giving effect to approximately $ of letters of credit issued under the Plaquemines Working Capital Facility), and approximately $ of working capital loans under the Calcasieu Pass Credit Facilities (after giving effect to approximately $ letters of credit issued under the Calcasieu Pass Working Capital Facility), all of which would have been secured. 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 securitiescould elect to accelerate all or a portion of our debt. A delay in COD of the Calcasieu Project or Phase 1 or 2 of the Plaquemines Project beyond a certain deadline could also result in an event of default under the Calcasieu Pass Credit Facilities or the Plaquemines Credit Facilities, respectively, and/or certain investors exercising step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project.

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 foreclose against 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, and the price of our Class A common stock.

In particular, 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 (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. As a result, the lenders under any such indebtedness could proceed to foreclose against 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, and the price of our Class A common stock.

Furthermore, if the Calcasieu Project does not commence commercial operation by a specified date certain (currently December 31, 2024, subject to certain extension rights), an event of default under the Calcasieu Pass Credit Facilities will occur. See “Description of Indebtedness and Project Financing—Project Debt Financing.” In addition, if the Calcasieu Project does not commence commercial operation by the date that is 45 days prior to the date certain under the Calcasieu Pass Credit Facilities, holders of preferred units or 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. 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

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our business, financial conditions and results of operations and the price of our Class A common stock. See “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Holdings, LLC Preferred Units—Step-In Right.”

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:

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expected supply is less than the amount hedged;

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the counterparty to the hedging contract defaults on its contractual obligations; or

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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’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

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 development 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 “Business—Governmental Regulation.” Approvals of FERC and DOE under Sections 3 and 7 of the Natural Gas Act, or the NGA, as well as several other material

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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, and to export the LNG produced at our projects. See also “Business—Environmental Regulation.” 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.

While we have received the applicable approvals from the Office of Fossil Energy and Carbon Management of the DOE authorizing the export of domestically produced LNG for the nameplate capacity as well as excess capacity up to the current permitted liquefaction capacity for the Calcasieu Project and the Plaquemines Project, our requests to increase the authorized export volumes from both projects to reflect an increased peak output have been granted only with respect to exports to FTA Nations while the requests with respect to Non-FTA Nations remain pending. Similarly, DOE has authorized LNG exports from the CP2 Project only to FTA Nations while our non-FTA application for that project remains pending. We have not yet made filings to the DOE regarding the export of any natural gas from the CP3 Project or the Delta Project. Moreover, we have not made any filings with DOE with respect to any of the potential bolt-on expansion opportunities at any of our projects.

In January 2024, the Biden administration announced a temporary pause on new authorizations of natural gas exports to non-FTA Nations while the DOE conducts studies to update its analyses regarding whether the exports are “not inconsistent with the public interest” to consider the latest available information regarding macro-economic impacts, domestic energy prices, potential greenhouse gas, climate or other environmental effects, and national security implications. We expect that this decision and the development of the studies will impact all of our pending applications for exports to Non-FTA Nations. DOE officials have publicly indicated that they expect the updated studies, including a public comment period, to be finalized around the first quarter of 2025. Accordingly, a change in administration resulting from the presidential election in November 2024 may impact the DOE’s final decision. On July 1, 2024, a Federal District Judge in Louisiana granted a motion for preliminary injunction by numerous states, holding the DOE pause appears to be unlawful and staying the pause in its entirety. Although the DOE’s pause has been stayed, the DOE has appealed the decision and there can be no assurance as to the final resolution of the legal challenges, the outcome of the DOE’s updates to its analyses and procedures, or the impact on our existing and future projects, including our related contracts. On August 31, 2024, DOE issued a non-FTA export authorization for one project (NFE Altamira FLNG, a 1.4 mtpa project) but limited its term to 5-years, ruling that a more complete record is needed to evaluate a longer term. We expect that at least most DOE long-term, non-FTA authorizations will be delayed until there is a change in administration and/or the DOE completes its studies to update its consideration of issues affecting the public interest implications of LNG exports. See “—Risks Relating to our Business—Our customers may terminate our SPAs if certain conditions are not met or for other reasons.”

While FERC has authorized the siting, construction and operation of the Calcasieu Project, the Plaquemines Project and the CP2 Project (and the related pipelines) under Sections 3 and 7 of the NGA, additional authorizations from the commissioners and/or staff of FERC to proceed with the construction of facilities for the Plaquemines Project and the CP2 Project, and to complete commissioning and place facilities into commercial service for each project, are required as part of FERC’s ongoing regulation of our projects. The FERC issued its order authorizing the CP2 Project in June 2024. In July 2024, a group of opponents composed mostly of environmental groups filed a request for rehearing of the FERC authorization, raising a number of challenges to the FERC authorization. In a notice issued on August 29, 2024, FERC denied rehearing by operation of law while providing for further consideration, and it is likely to issue a substantive order on rehearing in the coming

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months before it is required to submit the administrative record to the appellate court for review. Project opponents consisting of numerous environmentalist organizations and certain individuals filed petitions for review of FERC’s authorization order with the US Court of Appeals for the D.C. Circuit on September 4, 2024. In addition to that appeal, construction of the CP2 Project will be subject to ongoing oversight and needed additional authorizations by FERC in accordance with the terms and conditions of the CP2 Project FERC order, and we have already begun to submit implementation plans for that purpose. As of , 2024, we submitted a pre-filing to FERC for the CP3 Project. As of , 2024, the Delta Project remains in the FERC “pre-filing process.” We have not made any filings with FERC with respect to any of the potential bolt-on expansion opportunities at any of our 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 issue the non-FTA export authorization for the CP2 Project and for increases in the peak output for the Calcasieu and Plaquemines Projects, as well as for the FERC and DOE to act on future applications for the CP3 Project, the Delta Project or any potential bolt-on expansion opportunities in our projects in the future, 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 opposed the regulatory approvals necessary for the CP2 Project, as well as the increase in the permitted capacity for the Plaquemines Project. For example, in a December 11, 2023 letter to the DOE, a coalition of more than 200 environmental groups called on the DOE to deny the export license for Non-FTA Nations for the CP2 Project on the basis that it is not in the public interest due to the alleged impact of LNG exports on the climate and environmental justice, as well as domestic energy prices, and DOE subsequently issued its “pause” on new authorizations described above. In addition, the Sierra Club and similar organizations have appealed the recent FERC approval of the CP2 Project, and they have in some instances successfully challenged FERC orders authorizing other LNG and natural gas pipeline projects. As another instance of appeal, in November 2022, three environmental groups filed suit in a Louisiana court challenging the state’s decision not to require a coastal use permit for the Plaquemines Project, which was subsequently dismissed on venue grounds.

Opposition to our projects from environmental groups and other advocates may increase and strengthen over time. As noted above, opponents of the CP2 Project have appealed the FERC authorization of the project. Those entities likely will continue to oppose the CP2 Project and its regulatory authorizations, including its export authorization for Non-FTA Nations. Were the DOE to deny or limit that export authorization for the CP2 Project on the basis of climate or environmental justice concerns, it may result in increased advocacy against our projects from environmental groups and other advocates. 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, which may be entered after the granting of authorization by FERC (as in the existing appeal) or DOE (once it issues the non-FTA authorization), will not be successful or not delay our ability to develop the CP2 Project, the CP3 Project or the Delta Project, any bolt-on expansion to any of our projects we pursue in the future, or any other project 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

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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. In particular, certain of the foregoing approvals and permits must be obtained before construction of the CP2 Project, the CP3 Project and the Delta Project can begin, before the Plaquemines Project is completed, before commercial operations of the Calcasieu Project can commence, and before we can pursue any potential bolt-on expansion opportunities at our 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, prospects and the price of our Class A common stock.

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.

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. See “—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.”

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. For more information on these tariffs, see “Business—Governmental Regulation.” 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. See “—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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 $1.55 million currently (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

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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:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;

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improve data collection, integrate and analyze pipeline data;

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repair and remediate the pipeline as necessary; and

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implement preventative and mitigating actions.

We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. 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 to suffer potential adverse impacts to our operations. For instance, on May 4, 2023, PHMSA issued a proposed rulemaking implementing congressional mandates to reduce methane emissions from new and existing natural gas transmission, regulated gathering and distribution pipelines, natural gas storage, and LNG facilities. The proposed 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 investigating failures, and criteria for the design, configuration and maintenance of pressure relief devices. As a result, operators of pipelines and facilities affected by the final rule, once promulgated, may be required to make operational changes or modifications at their facilities to meet standards beyond current requirements, which changes or modifications 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, prospects and the price of our Class A common stock.

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

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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, prospects and the price of our Class A common stock.

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, prospects and the price of our Class A common stock.

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 because emissions of such gases are, according to EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. Federal and state regulatory authorities have been pursuing a number of regulatory and policy initiatives to reduce greenhouse gas, or GHG, emissions in the United States from a variety of sources, but such initiatives can be controversial and subject to change depending on legal and political developments. For example, in October 2015, the U.S. promulgated the Clean Power Plan, designed to reduce GHG emissions from existing power plants in the United States, and a regulation establishing GHG performance standards for new, modified and reconstructed power plants. The U.S. Supreme Court stayed implementation of the Clean Power Plan soon after its enactment, and on June 30, 2022, the Court held that EPA does not have authority under the Clean Air Act to set emissions caps based on a “generation shifting” approach as set forth in the Clean Power Plan. On May 9, 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.

Our business and operations could be affected by climate-related regulations. President Biden issued an executive order in his first day of office that established a commitment to addressing climate change and

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reducing GHG emissions. The executive order instructed federal agencies to review prior Administration regulations that conflict with this policy, including an immediate review of prior Administration emission standards for methane emissions from new oil and gas operations and to propose for the first time new methane emissions standards for existing oil and gas operations, which, as discussed below, occurred in November 2021 and were supplemented in December 2022. The January 20, 2021 executive order also directed agencies to take into account the cost of GHG emissions, or the social cost of carbon, in assessing the costs and benefits of regulatory actions. In December 2023, EPA issued an estimate of the social cost of carbon as being $190 per ton for the year 2020. While the full impact of this measure is difficult to predict, the inclusion of such costs has the potential to result in regulations that are more restrictive and costly for GHG emitters. On February 19, 2021 the current Administration formally rejoined the Paris Agreement and on April 22, 2021 during the Global Leaders Summit on Climate, announced a new target to achieve a 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. In December 2023 at the COP28 climate summit, representatives from nearly 200 nations, including the U.S., reached an agreement that calls on governments to transition away from fossil fuels in energy systems in order to achieve net zero by 2050, but noted that natural gas (including LNG) can play a role in cutting emissions. 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. Additionally, in May 2023, PHMSA announced new proposed rules to strengthen and update leak detection and repair standards for gas pipelines aimed at reducing methane emissions from covered pipelines by up to 55% by 2030. Such rules may impact our operations as well as those of our upstream supply chain partners.

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 ($900 per ton for emissions reported in calendar year 2024, rising to $1,500 per ton for such emission beginning with calendar year 2026) 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 will be subject to such excess emissions charge.

The United States Congress has also considered other legislation to restrict or regulate emissions of GHGs. While it remains unclear whether Congress will be able to agree on comprehensive climate legislation in the near future, energy legislation and other initiatives may 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 May 2024, the EU approved a regulation aimed at reducing methane emissions associated with natural gas, oil and coal imports and will impose 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.

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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. In February 2022, FERC released an interim policy statement for consideration of GHG emissions in natural gas infrastructure reviews, though it later converted it to a draft statement subject to further comment and it has not been finalized. In January 2023, the Council on Environmental Quality, or CEQ, issued interim guidance to assist agencies, including FERC, in analyzing GHG emissions and climate change effects under NEPA. Additionally, in September 2023, the White House directed agencies to consider the social cost of GHG emissions when conducting environmental reviews pursuant to NEPA. In May 2024, CEQ published its final “Phase 2” NEPA regulations which include specific direction to account for both climate change and environmental justice effects in NEPA reviews. Activism from environmental groups aimed at agency decision making, such as the December 2023 letter from the coalition of environmental groups urging the DOE to deny the export license for Non-FTA Nations for the CP2 Project, may lead FERC and other agencies to consider the indirect impacts of projects such as ours on upstream emissions of GHG or to quantify the economic effect of climate change impacts associated with GHG emissions of a project. In addition, regulatory initiatives have been proposed to require companies to publicly disclose information relating to the impacts of climate change and their direct, indirect and supply chain GHG emissions, such as the SEC rule on climate-related risks. Such initiatives 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 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, prospects and the price of our Class A common stock.

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We are involved and may in the future become involved in disputes and legal proceedings.

We are involved in and may in the future become involved in disputes as well as legal proceedings with public authorities, shareholders, suppliers, contractors, customers 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, we are currently involved in an arbitration proceeding with one of our construction contractors and in separate arbitration proceedings with certain of our customers under our post-COD SPAs related to the Calcasieu Project. See “—If we are unsuccessful in our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.”

Further, from time to time, we may be a party to various administrative, regulatory or other legal proceedings, and others may allege that we are in violation or in default under orders, statutes, rules or regulations relating to the environment, 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. For instance, BP previously filed a complaint with FERC in December 2023, which was subsequently withdrawn in July 2024, alleging that the Calcasieu Project has actually been in-service since 2022 and is operating commercially, seeking to consolidate the complaint proceeding with the ongoing proceeding for the commissioning of the project. In addition, when we filed with FERC in February 2024 for an extension of time, if deemed necessary, of the condition in our February 2019 FERC authorization order requiring the Calcasieu Project’s “proposed liquefaction facilities” be placed in-service within five years of the order, our long-term customers filed numerous responsive pleadings, predominantly seeking access to information filed with FERC on a confidential basis and to intervene in the on-going commissioning process. We have responded to customer filings in the extension of time filing proceeding, which remains pending before FERC.

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 defending against 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. 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, 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.

We are involved and may in the future become involved in disputes and arbitration proceedings with the customers under our SPAs. For example, in December 2022, a long-term customer of the Calcasieu Project submitted a request for arbitration to the International Chamber of Commerce, International Court of Arbitration, in accordance with the dispute resolution procedures of the post-COD SPA between us and that customer, asserting that we had failed to provide sufficient information or access to the Calcasieu Project and are delayed in achieving COD under the post-COD SPA. The remedies sought by the long-term customer are contract damages in excess of $1 billion (which is potentially subject to increase with the passage of time until COD occurs), rather than the termination of the post-COD SPA. The initial merits hearing for this arbitration proceeding occurred in September 2024.

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In May 2023, two additional long-term customers of the Calcasieu Project submitted separate requests for arbitration to the London Court of International Arbitration and the International Chamber of Commerce, International Court of Arbitration, respectively, in accordance with the dispute resolution procedures of the relevant post-COD SPAs with such customers, asserting, among other claims, that we are delayed in achieving COD under the post-COD SPA. The remedies sought by such long-term customers are (a) orders requiring us to immediately notify the relevant long-term customer of the occurrence of COD of the Calcasieu Project or otherwise deliver LNG cargos to the relevant long-term customer at the contract price set forth in the applicable post-COD SPA; and (b) contract damages of approximately $1.5 billion and $1.7 billion (each of which is potentially subject to increase with the passage of time until COD occurs), respectively, rather than the termination of the relevant post-COD SPAs. The hearings for such two arbitration proceedings have been scheduled for October 2024 and November 2024, respectively.

In August 2023, two additional long-term customers of the Calcasieu Project submitted separate requests for arbitration to the International Chamber of Commerce, International Court of Arbitration in accordance with the dispute resolution procedures of the relevant post-COD SPAs with such customers, asserting, among other claims, that we are delayed in achieving COD under the relevant post-COD SPA. The hearings for such two arbitration proceedings have been scheduled for June 2025 and July 2025, respectively. In December 2023, one additional long-term customer of the Calcasieu Project submitted a request for arbitration to the International Chamber of Commerce, International Court of Arbitration in accordance with the dispute resolution procedures of the post-COD SPA between us and that customer, asserting among other claims that we are delayed in achieving COD under the relevant post-COD SPA. The remedies sought by each of the second group of three long-term customers are (a) orders requiring us to immediately notify the relevant long-term customer of the occurrence of COD of the Calcasieu Project or otherwise deliver LNG cargos to the relevant long-term customer at the contract price set forth in the applicable post-COD SPA; and (b) contract damages in an amount to be determined in excess of $250 million (in the case of one such customer) or $400 million (in the case of two such customers), rather than the termination of the relevant post-COD SPAs.

Further, in March 2024, a short-term customer of the Calcasieu Project submitted a request for arbitration to the International Chamber of Commerce, International Court of Arbitration in accordance with the dispute resolution procedures of the post-COD SPA between us and that customer. Such customer has raised substantially the same assertions as the arbitration proceedings described above and is seeking contract damages of $200 million (which is potentially subject to increase with the passage of time until COD occurs), as well as an additional claim relating to an undelivered commissioning cargo. Additionally, all such customers who have asserted that we are delayed in achieving COD have also disputed that the delay to COD constitutes a force majeure event in the context of their arbitration proceedings. We disagree with the assertions in each of these requests for arbitration, and intend to defend ourselves in the arbitration proceedings in accordance with each underlying post-COD SPA. We also note that, while we believe that the foregoing assertions in each request for arbitration are unsubstantiated, we further believe that any award of contract damages would be subject to the relevant seller aggregate liability cap under the relevant post-COD SPA. However, there can be no assurance that we will be successful in defending such claims or establishing that any such claim is subject to the liability cap under the relevant post-COD SPA.

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 we are unsuccessful in defending ourselves against any of the claims mentioned above, the amounts we 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. Further, a termination of, or

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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, lead to an acceleration of our outstanding debt under the Calcasieu Project and foreclosure against 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, prospects and the price of our Class A common stock.

We have also notified all of our customers under the Calcasieu Foundation SPAs of the anticipated delay to COD, indicating that such delay is due to a force majeure event. As a result of such designation, the deadline for COD in such post-COD SPAs would be extended and such customers will not be entitled to terminate their respective post-COD SPAs as a result of failure to designate COD until June 2025. All of such customers have questioned (including, as applicable, in the post-COD SPA arbitration proceedings described above) whether the delay constitutes a force majeure event and they could assert that, notwithstanding our declaration of force majeure, they are entitled to terminate their post-COD SPAs. Discussions with such customers with respect to this force majeure event remain ongoing. Such customers may also seek contract damages, and several such customers have already sought contractual damages in connection with the alleged delay in achieving COD for the Calcasieu Project as described above. Any such claims could be substantial, and there can be no assurance that we will be successful in defending any such claims.

If any of our customers were to successfully terminate their post-COD SPAs with us for the Calcasieu Project, we would need to replace those customers and/or amend our existing post-COD SPAs, 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 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 Calcasieu Project or Phase 1 or 2 of the Plaquemines Project beyond a certain deadline could also result in an event of default under the Calcasieu Pass Credit Facilities or the Plaquemines Credit Facilities, respectively, and/or certain investors exercising step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project.”

Risks Relating to Intellectual Property, Data Privacy and Cybersecurity

Hostile cyber intrusions, or other issues with our information technology, could severely impair 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 severely disrupt 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. For example, the operator of the Colonial Pipeline, an unrelated third-party, was forced to pay $4.4 million in ransom to hackers as the result of a cyber-attack disabling the pipeline for several days in May 2021. The attack also resulted in gasoline price increases and shortages across the East Coast of the United States.

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. Such security threats are

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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 will be 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, prospects and the price of our Class A common stock.

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 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.

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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 there is discussion in Congress of 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, including the routing of the piping and valves within the liquefaction modules and optimization of other module designs, the sharing of supporting equipment between individual liquefaction trains, and the management of mixed refrigerant in the liquefaction process.

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 claims against 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, prospects and the price of our Class A common stock.

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Risks Relating to this Offering and Ownership of Our Class A Common Stock

Our Class B common stock has ten votes per share and our Class A common stock, which is the stock we are offering in this offering, 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. See “Description of Capital Stock—Common Stock.” Following this offering, VG Partners will beneficially own shares of Class B common stock, or 100% of all shares of Class B common stock then outstanding. As a result, VG Partners will hold approximately % of the combined voting power of our Class A common stock and our Class B common stock and will be 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. Furthermore, under Delaware law and our amended and restated certificate of incorporation and amended and restated bylaws, VG Partners will be 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 will initially have the sole ability to elect the board of directors. Other holders of our common stock will, 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 will have 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. See “Description of Capital Stock.”

An active, liquid trading market for our Class A common stock may not develop or be sustained, and there is the possibility of significant fluctuations in the price of our Class A common stock.

Prior to this offering, there has been no public market for shares of our Class A common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on or how liquid that market may become. If an active trading market does not develop, the market for and liquidity of shares of our Class A common stock may be adversely affected and you may have difficulty selling any of our Class A common stock that you purchase. The initial public offering price of shares of our Class A common stock is, or will be, determined by negotiation between us and the underwriters and may not be indicative of prices that will prevail following the completion of this offering. The market price of shares of our Class A common stock may decline below the initial public offering price, and you may not be able to resell your shares of our Class A common stock at or above the initial public offering price. We cannot assure you as to:

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the likelihood that an active market will develop for our Class A common stock;

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the liquidity of any such market;

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the ability for you to sell your Class A common stock;

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the price that you may obtain for your Class A common stock;

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if an active market does develop, we cannot assure you as to how long such market will be sustained, if at all;

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the price of LNG and natural gas;

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the completion of the regulatory approval process required to construct and operate our projects and the timing of any such completion;

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the commencement and timely completion of construction of our projects;

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our quarterly or annual earnings or those of other companies in our industry;

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actual or potential non-performance by any customer under any LNG sales contract that we may enter into;

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announcements by us or our competitors of significant contracts;

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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;

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the failure of securities analysts to cover our Class A common stock after this offering or changes in financial or other estimates by analysts;

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future sales of our Class A common stock;

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regulatory developments;

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litigation and governmental investigations; and

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other factors described in these “Risk Factors” and elsewhere in this prospectus.

These and other factors may cause the market price and demand for 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. 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, in the past, when the market price of a stock has been volatile, holders of that stock have instituted securities class action litigation against the company that issued the stock. If any of our stockholders brought a lawsuit against us, we could incur substantial costs defending the lawsuit. Such a lawsuit could also divert the time and attention of our management from our business.

The trading market for our Class A common stock will 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,

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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. See “Material U.S. Federal Income and Estate Tax Consequences for Non-U.S. Holders of Common Stock.”

Our amended and restated certificate of incorporation will contain a provision renouncing our interest and expectancy in certain corporate opportunities in favor of the Pre-IPO Stockholders, which could adversely affect our business or future prospects.

Our amended and restated certificate of incorporation that will be effective upon completion of this offering will provide that, to the fullest extent permitted by applicable law, we renounce any right, interest or expectancy in any business opportunity, or being offered an opportunity to participate in any business opportunity, that may from time to time be presented to VG Partners and each other holder of shares of our common stock outstanding immediately prior to consummation of this offering, or collectively, the Pre-IPO Stockholders, or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. No such person shall be liable to us for breach of any statutory, fiduciary, contractual or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director.

As a result, the Pre-IPO Stockholders or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us) may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they or their affiliates have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing of our interest and expectancy in any business opportunity that may be presented from time to time to the Pre-IPO Stockholders or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us) could adversely impact our business or future prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See “Description of Capital Stock—Corporate Opportunities.”

New investors in our Class A common stock will experience immediate and substantial book value dilution after this offering.

The initial public offering price of our Class A common stock will be higher than the pro forma net tangible book value per share of the outstanding Class A common stock immediately after the offering. Based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) and our net tangible book value as of , 2024, if you purchase our Class A common stock in this offering you will pay more for your shares than the amounts paid by our existing stockholders for their shares and you will suffer immediate dilution of approximately $ per share in pro forma net tangible book value. As a result of this dilution, investors purchasing stock in this offering may receive significantly less than the full purchase price that they paid for the shares purchased in this offering in the event of a liquidation.

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As of , 2024, we also have approximately outstanding stock options to purchase common stock with a weighted average exercise price of $ . To the extent that these options are exercised, there will be further dilution.

We cannot predict the impact our dual class structure may have on the market price of our Class A common stock, especially given restrictions on companies with multiple class structures from certain index providers.

We cannot predict whether our dual class structure will result in a lower or more volatile market price of our Class A common stock, in adverse publicity or other adverse consequences. Certain index providers have announced restrictions on including companies with multiple class share structures in certain of their indices. For example, FTSE Russell does not allow most newly public companies utilizing dual or multi-class capital structures to be included in their indices and while S&P Dow Jones Indices previously did not allow companies with multiple class share structures in certain of their indices, they have since announced that companies with multiple share class structures will be considered eligible for the S&P Composite 1500 and its component indices, including the S&P 500, the S&P MidCap 400 and the S&P SmallCap 600, if they meet all other eligibility criteria.

Under these policies, our dual class capital structure would make us ineligible for inclusion in such indices. Given the sustained flow of investment funds into passive strategies that seek to track certain indices, exclusion from stock indices would likely preclude investment by many of these funds and could make our Class A common stock less attractive to other investors. Additionally, proxy advisory firms have expressed opposition to dual class share structures, stating that they would recommend voting against the management of companies with such dual class share structures and unequal voting rights when the companies did not provide for a reasonable sunset of such structures. As a result, the market price of our Class A common stock could be materially adversely affected.

Certain provisions of our amended and restated certificate of incorporation and amended and restated bylaws may have anti-takeover effects, which could limit the price investors might be willing to pay in the future for our Class A common stock. In addition, Delaware law may inhibit takeovers of us and 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 that will be effective upon completion of this offering 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 will include provisions that, among other things:

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provide for a classified board of directors with staggered three-year terms (except that if VG Partners beneficially owns at least 50% of the combined voting power of our then-outstanding common stock, our board will consist of a single class of directors each serving one year terms);

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do not permit directors to be removed from the board of directors without cause (except that if VG Partners beneficially owns at least 50% of the combined voting power of our then-outstanding common stock, directors may be removed with or without cause);

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do not permit cumulative voting in the election of directors, which would otherwise allow less than a majority of stockholders to elect director candidates;

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authorize the issuance of “blank check” preferred stock without any need for action by stockholders;

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limit the ability of stockholders to call special meetings of stockholders or to act by written consent in lieu of a meeting (except that if VG Partners beneficially owns at least 50% of the combined voting power of our then-outstanding common stock, 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);

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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 if VG Partners beneficially owns at least 50% of the combined voting power of our then-outstanding common stock, such amendments require only the affirmative vote of a majority of the outstanding shares of common stock); and

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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 beneficially owns, in the aggregate, at least 10% of the total combined voting power of our common stock, such advance notice procedure will not apply to VG Partners.

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. See “Description of Capital 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 such time as VG Partners no longer beneficially owns at least 25% of the combined voting power of our then-outstanding common stock. 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 66²/₃% 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, deferring or preventing a change in control, and may discourage bids for our Class A common stock at a premium over our market price.

While we currently expect that we will declare and pay 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 your investment could depend on the appreciation of our Class A common stock. Accordingly, you should not purchase shares of our 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. For more details, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources,” “Risk Factors—Risks Related to Our Indebtedness and Financing—Certain of our debt agreements impose significant operating and financial

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

restrictions on our subsidiaries, and the preferred units of our subsidiaries also give the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities” and “Risk Factors—Risks Related to Our Indebtedness and Financing—As a holding company, the Company depends on the ability of its subsidiaries to transfer funds to it to meet its obligations.”

If we or VG Partners sell additional shares of our Class A common stock after this offering 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. Upon completion of this offering, we will have a total of shares of our Class A common stock outstanding or shares if the underwriters exercise in full their option to purchase additional shares of our Class A common stock. All of the shares of our Class A common stock sold in this offering will be 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. See “Shares Eligible for Future Sale.”

In addition, upon completion of this offering, an aggregate of shares of our Class B common stock are outstanding, all of which are 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. Any shares of our Class A common stock issued upon conversion of our Class B common stock will be “restricted securities” as defined in Rule 144 and 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.

We, and , have agreed, subject to certain exceptions, not to dispose of or hedge any shares of our Class A common stock or securities convertible into or exchangeable for shares of our Class A common stock for days from the date of this prospectus, except with prior written consent. See “Underwriting.” Upon the expiration of the lock-up agreements, all of such shares will be 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. We expect that will continue to be considered an affiliate following the expiration of the lock-up period based on its expected share ownership. However, subject to the expiration or waiver of the lock-up period, , as well as the other Pre-IPO Stockholders 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. See “Shares Eligible for Future Sale—Registration Rights” and “Certain Relationships and Related Person Transactions—Existing Shareholders’ Agreement.”

We intend to file one or more registration statements on Form S-8 under the Securities Act to register shares of our Class A common stock issued under the 2024 Plan. Any such Form S-8 registration statements will automatically become effective upon filing. Accordingly, shares registered under such registration statements will be available for sale in the open market. If equity securities granted under our 2024 Plan 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.

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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.

After this offering we will have 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. For additional information concerning the awards under the 2024 Plan that we intend to grant in connection with this offering or that will be outstanding at the time of this offering, see “Summary—The Offering.”

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. The conversion of Class B common stock into Class A common stock as a result of such exchanges or transfers would dilute holders of Class A common stock, including holders of shares purchased in this offering, in terms of the number of outstanding shares of Class A common stock and voting power within Class A common stock.

Any Class A common stock that we issue, including under our 2024 Plan or other equity incentive plans that we may adopt in the future, would dilute the percentage ownership held by the investors who purchase Class A common stock in this offering. For example, in connection with this offering, we intend to file a registration statement on Form S-8 to register the shares of our Class A common stock that we expect to reserve for issuance under our 2024 Plan. It is anticipated that additional equity awards will be granted to our employees and directors following the completion of this offering, from time to time, under this plan and other equity incentive plants that we may adopt in the future.

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 will authorize 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 respecting 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 the Class A common stock. See “Description of Capital 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.

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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 estimates and assumptions may evolve or change over 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.

We have broad discretion in the use of our net proceeds from this offering and may not use them effectively.

Our management will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our operating results or enhance the value of our Class A common stock. Our stockholders may not agree with the manner in which our management chooses to allocate and spend the net proceeds. Our management’s failure to apply these funds effectively could result in financial losses that could have a material adverse effect on our business and cause the price of our Class A common stock to decline. Pending their use, we may invest our net proceeds from this offering in a manner that does not produce income or that loses value. See “Use of Proceeds.”

We will incur increased costs and become subject to additional regulations and requirements as a result of becoming a public company, which could lower our profits, make it more difficult to run our business or divert management’s attention from our business.

As a public company, we will be required to commit significant resources and management time and attention to the requirements of being a public company, which will cause us to incur significant legal, accounting and other expenses that we have not incurred as a private company, including costs associated with public company reporting requirements. We also will 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 , and compliance with these requirements will place significant demands on our legal, accounting and finance staff and on our accounting, financial and information systems. Although we have a number of directors, officers and employees with experience in complying with these requirements applicable to public companies, there can be no assurance that we will be successful in complying with these requirements. The expenses incurred by public companies generally for reporting and corporate governance purposes have been increasing. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, although we are currently unable to estimate these costs with any degree of certainty. These laws and regulations also could make it more difficult or costly for us to obtain certain types of insurance, including director and officer liability insurance, and we may be forced to accept reduced policy limits and coverage, higher retention, or incur substantially higher costs to obtain the same or similar coverage. These laws and regulations could also make it more difficult for us to attract and retain qualified persons to serve on our board of directors, our board committees or as our executive officers. Furthermore, if we are unable to satisfy our obligations as a public company, we could be subject to delisting of our Class A common stock, fines, sanctions and other regulatory action and potentially civil litigation.

As a result of being a public company, we are obligated to develop and maintain proper and effective internal controls over financial reporting, and any failure to maintain the adequacy of these internal controls may adversely affect investor confidence in our company and, as a result, the value of our Class A common stock.

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, . 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

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

our annual report required to be filed with the SEC for the fiscal year ending December 31, . We have recently commenced the costly and challenging process of compiling the system and processing documentation necessary to perform the evaluation needed to comply with Section 404 of the Sarbanes-Oxley Act, but we may not be able to complete our evaluation, testing and any required remediation in a timely fashion once initiated. Our compliance with Section 404 of the Sarbanes-Oxley Act will require that we incur substantial expenses and expend significant management efforts. We currently do not have an internal audit group, and we will need to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge and 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 is 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 is 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.

Upon the listing of our Class A common stock on , we will be a “controlled company” within the meaning of rules and, as a result, will 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.

Upon completion of this offering, VG Partners will continue to control a majority of the voting power of our outstanding common stock, and we will be a “controlled company” within the meaning of corporate governance standards. Under 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 corporate governance requirements, including the requirements that:

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a majority of the board of directors consist of independent directors;

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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

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there be an annual performance evaluation of the nominating and corporate governance and compensation committees.

Consistent with these exemptions, upon closing this offering, we will not have . Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements.

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Our amended and restated certificate of incorporation will designate 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 could limit 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 will provide 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 will 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 litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, our amended and restated certificate of incorporation will further provide that the federal district courts of the United States of America will be 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.

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, prospects and the price of our Class A common stock. Both domestic and international markets experienced significant inflationary pressures in fiscal years 2022 and 2023 and inflation rates in the U.S., as well as in other countries in which we operate, may remain at elevated levels for the near-term. In addition, the Federal Reserve in the U.S. and other central banks in various countries have raised, and may again raise, interest

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

rates in response to concerns about inflation, which, coupled with reduced government spending and volatility in financial markets, may have the effect of further increasing economic uncertainty and heightening these risks. Interest rate increases or other government actions taken to reduce inflation could also 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, prospects and the price of our Class A common stock. 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.”

Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.

A terrorism, including a 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.” A terrorism, including a 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 terrorism, including 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, prospects and the price of our Class A common stock.

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

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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.

The Inflation Reduction Act, enacted on August 16, 2022, includes the implementation of a new 15% corporate alternative minimum tax, or the CAMT, on adjusted financial statement income for applicable corporations, effective for tax years beginning after December 31, 2022. CAMT is a novel and new approach for calculating corporate tax liability. Many unanswered questions remain on how the operative rules for CAMT will be implemented and interpreted. The CAMT may lead to volatility in our cash tax payment obligations, particularly in periods of significant commodity, currency or financial market variability resulting from potential changes in the fair value of our derivative instruments.

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 prior administration have given rise to uncertainty regarding the future of international trade agreements and the United States’ position on international trade. For example, the prior administration imposed tariffs on a range of products from China, which led China to also impose tariffs on certain U.S. goods in retaliation, including a 25% tariff on U.S. LNG imports. The United States had also stated that further tariffs may be imposed on additional products imported from China if a trade agreement was not reached. On January 15, 2020, a “phase one” trade deal was signed between the United States and China and was accompanied by a decision from the United States to cancel a plan to increase tariffs on an additional list of Chinese products. However, given the limited scope of the phase one agreement, concerns over the stability of bilateral trade relations remain. As of , 2024, we had entered into long-term, post-COD SPAs for an aggregate of mtpa with Chinese customers across all of our projects. Any future changes to the United States’ trade relationship with China, 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 Chinese customers for U.S. LNG exports. At this time, we cannot assure you that a broader trade agreement will be successfully negotiated between the United States and China to reduce or eliminate the existing tariffs. It also remains unclear what additional actions, if any, the current administration will take with respect to the trade relationships with China or whether China will impose additional burdens on U.S. companies. Moreover, the uncertainty regarding the policies of the current administration with respect to the future of trade partnerships and relations may reduce our competitiveness in countries that may be affected by those policies, such as China, whether or not the current administration ultimately takes any such actions. Any of these factors could adversely affect our ability to market the remaining production capacity of our projects, which could have a material adverse effect on the viability of our projects and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

The outbreak of any infectious diseases or other illness, including COVID-19 and its variants, could adversely impact our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock.

We are subject to risks related to outbreaks of infectious diseases, including COVID-19 and its variants. The extent to which an outbreak of an infectious disease or other illness, including COVID-19, 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

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

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.

The factors discussed above could have a material adverse effect on our business, results of operations and financial condition. In addition, certain of our construction contractors and suppliers may attempt to seek contractual relief in response to the impacts of the COVID-19 pandemic, or any future pandemic, on their performance. Any changes arising from such requests could result in delays or increased costs, which could have a material adverse effect on our business.

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.

Developments related to the ongoing war between Russia and Ukraine and the ongoing conflicts in the Middle East 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 retaliates against Russia for its invasion. This invasion, as well as the ongoing conflicts in the Middle East, including the Israel-Hamas conflict and other hostilities in the region have led, are currently leading, and for an unknown period of time will continue to lead to disruptions in local, regional, national, and global markets and economies affected thereby. These disruptions caused by the invasion and such conflicts have included, and may continue to include, political, social, and economic disruptions and uncertainties and material increases in certain commodity prices that could adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects and the price of our Class A common stock.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made statements under the captions “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business,” “LNG Industry Overview” and in other sections of this prospectus that are forward-looking statements. All statements, other than statements of historical facts, included herein are “forward-looking statements.” In some cases, forward-looking statements can be identified by terminology such as “may,” “might,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

These forward-looking statements, which are subject to risks, uncertainties and assumptions about us, may include projections of our future financial performance, expectations regarding the development, construction, commissioning and completion of our projects, estimates of the cost of our projects and schedule to construct and commission our projects, our anticipated growth strategies and anticipated trends impacting our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements, including those factors discussed under the caption entitled “Risk Factors.” Those factors include the following:

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our potential inability to maintain profitability, maintain positive operating cash flow and ensure adequate liquidity in the future;

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our limited track record and historical financial information, and the lack of assurance that our business will continue to be successful;

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our need for significant additional capital to construct and complete some future projects, and our potential inability to secure such financing on acceptable terms, or at all;

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our potential inability to construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, which could limit our growth prospects;

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significant operational risks related to our natural gas liquefaction and export projects, including the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project, any future projects we develop, our LNG tankers, and our regasification terminal usage rights;

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our potential inability to accurately estimate costs for our projects, and potential changes to our estimates due to various factors;

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potential delays in the construction of our projects beyond the estimated development periods;

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our potential inability to enter into the necessary contracts to construct the CP2 Project, the CP3 Project or the Delta Project on a timely basis or on terms that are acceptable to us;

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the potential that counterparties in certain of our contractual arrangements relating to the development and construction of our projects may exercise their existing termination rights;

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the potential inability of our contractors to perform their obligations under our multiple procurement and construction contracts;

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our potential inability to enter into post-COD SPAs with customers for, or to otherwise sell, the total expected nameplate capacity at the CP2 Project, the CP3 Project, the Delta Project or any future projects we develop;

•

our dependence on our EPC and other contractors for the successful completion of our projects and delivery of our LNG tankers;

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

our dependence on third party vendors and service providers for the provision of certain services and equipment to our projects and their potential inability to perform according to the terms of the applicable agreements;

•

various economic and political factors, including opposition by environmental or other public interest groups, which could negatively affect the timing or overall development, construction and operation of our projects;

•

the effects of FERC regulation on our interstate natural gas pipelines and their FERC gas tariffs;

•

our potential inability to secure the right or the potential risk of losing the right to situate the pipelines required for any of our projects on property owned by third parties, or our potential inability to timely complete the construction of those pipelines;

•

the potential lack of local government and community support required for the construction of our projects;

•

the potential that 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 risk that the natural gas liquefaction system and mid-scale design we utilize at our projects will not achieve the level of performance or other benefits that we anticipate;

•

potential additional risks arising from the phased commissioning start-up of our projects;

•

our potential inability to retain and attract executive officers and other skilled professional and technical employees;

•

our dependence on the strategic direction of our founders;

•

risks that we or our contractors, including our EPC contractors, may experience increased labor costs, and the unavailability of skilled workers or our potential failure to attract and retain qualified personnel;

•

the potential risk that our customers may terminate our SPAs if certain conditions are not met or for other reasons;

•

our potential inability to generate cash under our post-COD SPAs due to our dependence upon the performance by a limited number of our customers;

•

the significant uncertainty in our ability to generate proceeds and the amount of proceeds that will regularly be received from sales of commissioning cargos and excess cargos due to volatility and variability in the LNG markets;

•

potential decreases in the price of natural gas and its related impact on our ability to pay the cost of gas transportation, the payment of a premium by us for feed gas relative to the contractual price we charge our customers, or other impacts to the price of natural gas resulting from inflationary pressures;

•

our potential inability to sell uncontracted or excess liquefaction capacity or produce LNG in excess of the nameplate capacity of our facilities;

•

our reliance on third-party engineers to estimate the future capacity ratings and performance capabilities of our projects, which may prove to be inaccurate;

•

our potential inability to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under our SPAs;

•

the potential negative impacts of seasonal fluctuations on our business;

•

our limited diversification;

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

our potential inability to obtain, maintain or comply with necessary permits or approvals from governmental and regulatory agencies on which the construction of our projects depends, including as a result of opposition by environmental and other public interest groups;

•

the risk that the construction and operations of natural gas pipelines and pipeline connections for our projects suffer cost overruns and delays related to obtaining regulatory approvals, development risks, operational hazards and other risks;

•

the risk of a reduction of volumes of natural gas transported to our facilities due to any third-party pipelines and other facilities interconnected to our pipelines and facilities becoming unavailable to transport natural gas or suffering any reductions in the capacity of, or the allocations to, interconnecting third-party pipelines;

•

the potential of increased costs and liabilities due to pipeline safety integrity programs and repairs;

•

our current and potential involvement in disputes and legal proceedings, including the arbitrations and other proceedings currently pending against us and the possibility of a negative outcome in any such dispute or proceeding and the potential impact thereof on our results of operations, liquidity and our existing contracts;

•

the risks related to the development and/or contracting for additional gas transportation capacity to support the operation and expansion capacity of our LNG projects;

•

the risks related to the chartering, acquisition and/or building of LNG tankers, including the risk of delays in delivery, increases in charter, price or building costs, and ability to raise any capital necessary to finance the chartering, acquisition and/or building of any LNG tankers;

•

the risks related to the management and operation of our future LNG tanker fleet and our future regasification terminal usage rights;

•

the potential that various tax incentive programs the State of Louisiana offers that we plan to utilize may not be available or be available in diminished form;

•

the uncertainty regarding the future of international trade agreements and the United States’ position on international trade;

•

severe weather events, hurricanes or other disasters which could potentially cause interruptions 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;

•

our potential inability to insure against all potential risks and the risk that we may become subject to higher than expected insurance premiums, as well as risks associated with our captive insurance company;

•

the possibility of hostile cyber intrusions;

•

our ability to construct LNG facilities that produce LNG at volumes in excess of their nameplate capacity, and our ability to market and sell any such volumes produced by our LNG facilities in excess of their nameplate capacity;

•

competition in the LNG industry and the potential that many of our competitors may have greater financial, engineering, marketing and other resources than we have;

•

competition based upon the international market price for LNG;

•

the potential that LNG exported from the United States fails to remain a competitive source of energy for international markets;

•

the potential risk of developments related to the ongoing war between Russia and Ukraine and the ongoing conflicts in the Middle East;

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

cyclical or other changes in the demand for and price of LNG and natural gas;

•

potential shortages of LNG tankers worldwide;

•

the potential that technological innovation may render our anticipated competitive advantage or our processes obsolete;

•

the potential effects of existing and future environmental and similar laws and governmental regulations on compliance costs, operating and/or construction costs and restrictions;

•

the potential lack of an active, liquid trading market for our Class A common stock, and the possibility of significant fluctuations in the price of our Class A common stock;

•

our indebtedness levels, and the fact that we may be able to incur substantially more indebtedness, which may increase the risks created by our substantial indebtedness;

•

risks of downgrade, suspension or withdrawal of the rating assigned by a rating agency to us could impact our cost of capital;

•

concentration of control over our management, affairs and over matters requiring stockholder approval with VG Partners as a result of the dual class structure of our common stock and VG Partners’ ownership of our Class B common stock;

•

potential conflicts of interest with VG Partners or any of its officers, directors, agents, shareholders, members, partners, affiliates or subsidiaries (other than us); and

•

risks related to other factors discussed under “Risk Factors” of this prospectus.

You should specifically consider the numerous risks outlined under “Risk Factors.” Moreover, new risks emerge from time to time as we operate in a very competitive and rapidly changing business environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Given these uncertainties, you should not place undue reliance on these forward-looking statements.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors or to assess the impact of each such factor on us.

Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made except as required by the federal securities laws. If one or more of these or other risks or uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may vary materially from what we may have expressed or implied by these forward-looking statements. We caution that you should not place undue reliance on any of our forward-looking statements. You should specifically consider the factors identified in this prospectus that could cause actual results to differ before making an investment decision to purchase our Class A common stock. Furthermore, new risks and uncertainties arise from time to time, and it is impossible for us to predict those events or how they may affect us.

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be approximately $ billion, or approximately $ billion if the underwriters exercise their option to purchase additional shares in full, assuming an initial public offering price of $ per share (the midpoint of the range set forth on the cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses.

The intended use of net proceeds from this offering represents our intentions based upon our present plans and business conditions. We cannot predict with certainty all of the particular uses for the proceeds of this offering or the amounts that we will actually spend on the uses set forth above. Accordingly, our management will have broad discretion in applying the net proceeds of this offering. The timing and amount of our actual expenditures will be based on many factors, including cash flows from operations and the anticipated growth of our business. See “Risk Factors—Risks Relating to this Offering and Ownership of Our Class A Common Stock—We have broad discretion in the use of our net proceeds from this offering and may not use them effectively.”

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

DIVIDEND POLICY

On September 13, 2024, our board of directors declared the payment of cash dividends to our stockholders in an aggregate amount of $160 million that, subject to applicable law, will be paid on a pro rata basis in four equal installments of $40 million over four consecutive calendar quarters on the last business day of each such calendar quarter, commencing on September 30, 2024. To the extent the record date for any such dividend falls after the date of this prospectus, such dividend will be payable to holders of the Class A common stock and holders of the Class B common stock. Our certificate of incorporation provides that holders of the Class A common stock and holders of the Class B common stock will be treated equally and ratably on a per share basis with respect to any such dividends (unless different treatment of the shares of a class is approved by the affirmative vote of the holders of a majority of the outstanding shares of the applicable class of common stock treated adversely, voting separately as a class).

We currently expect that we will declare and pay cash dividends on our common stock from time to time. However, 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, general economic business conditions, industry practice, 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 your investment could depend on the appreciation of our Class A common stock. You should not purchase shares of our common stock with the expectation of receiving cash dividends. See “Risk Factors—Risks Relating to this Offering and Ownership of Our Class A Common Stock—We cannot guarantee that we will pay 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.” 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. For more details, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources,” “Risk Factors—Risks Related to Our Indebtedness and Financing—Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred units of our subsidiaries also give the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities” and “Risk Factors—Risks Related to Our Indebtedness and Financing—As a holding company, the Company depends on the ability of its subsidiaries to transfer funds to it to meet its obligations.”

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

CAPITALIZATION

The following table sets forth our cash, cash equivalents and capitalization as of , 2024:

•

on an actual basis;

•

on a pro forma basis, giving effect to (1) the -for-1 stock split on our Class A common stock to be effected in connection with this offering, immediately prior to the automatic conversion described in (2); (2) the automatic conversion of all outstanding shares of our Class A common stock held by VG Partners immediately prior to the completion of this offering into an equal number of shares of our Class B common stock; and (3) the filing and effectiveness of our amended and restated certificate of incorporation, each of which will occur immediately prior to the completion of this offering; and

•

on a pro forma as adjusted basis to reflect the sale by us of shares of Class A common stock in this offering, at an assumed initial public offering price of $ per share, the midpoint of the range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses, and the application of the net proceeds to us therefrom as described under “Use of Proceeds”.

Each $1.00 increase (decrease) in the public offering price per share would increase (decrease) our cash and cash equivalents, total stockholders’ equity and total capitalization, after deducting estimated underwriting discounts and commissions, by $ million (assuming the number of shares of our Class A common stock offered by us, as set forth on the cover of this prospectus, remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares). We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares in the number of shares of our Class A common stock offered by us would increase (decrease) our cash and cash equivalents, total stockholders’ equity and total capitalization, after deducting estimated underwriting discounts and commissions, by $ million (assuming the public offering price remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares).

This table should be read in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Description of Indebtedness and Project Financing” and the audited consolidated financial statements and notes thereto appearing elsewhere in this prospectus.

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

As of , 2024

Actual

Pro Forma

Pro Forma
As Adjusted

(in millions)

Cash and cash equivalents

Restricted cash, current and noncurrent

Total

Debt:

Project level debt⁽¹⁾⁽²⁾

VGLNG debt⁽¹⁾⁽³⁾

Total debt

Redeemable stock of subsidiary⁽⁴⁾

Equity:

Preferred stock, $0.01 par value per share, shares authorized actual, pro forma and pro forma as adjusted, no shares outstanding actual, pro forma and pro forma as adjusted

Class A common stock, $0.01 par value per share, shares authorized actual, shares authorized pro forma and shares authorized pro forma as adjusted, shares outstanding actual, shares outstanding pro forma and shares outstanding pro forma as adjusted

Class B common stock, $0.01 par value per share, shares authorized actual, shares authorized pro forma and shares authorized pro forma as adjusted, no shares outstanding actual, shares outstanding pro forma and shares outstanding pro forma as adjusted

Additional paid-in capital

Retained earnings

Accumulated other comprehensive loss

Total Venture Global, Inc. stockholders’ equity

Non-controlling interests⁽⁵⁾

Total capitalization

(1)	Balances of the VGLNG Senior Secured Notes, the Calcasieu Project Credit Facilities, the VGCP Senior Secured Notes and the Plaquemines Credit Facilities reflect the full outstanding principal amount of those obligations without reduction for unamortized premiums, discounts and debt issuance costs.

(2)

As of , we had $ billion available additional borrowing capacity under the senior secured term loan facility of the Calcasieu Project Credit Facilities and $ million of letters of credit issued and outstanding thereunder, and we had approximately $ million of unutilized borrowing capacity under the working capital facility of the Calcasieu Project Credit Facilities. As of , we had $ billion of undrawn term loan commitments under the Plaquemines Credit Facilities and $ million of letters of credit issued and outstanding thereunder and $ billion undrawn working capital commitments thereunder. Between , 2024 and , 2024, we prepaid an aggregate of $ million of outstanding borrowings under the Calcasieu Project Credit Facilities and we prepaid an aggregate of $ million of outstanding borrowings under the Plaquemines Credit Facilities.

(3)	Consists of the VGLNG Senior Secured Notes.

(4)

Represents third-party interests in the net assets of the Company’s subsidiary, Calcasieu Pass Funding, LLC, resulting from the issuance of redeemable stock, whereby a fund associated with Stonepeak Infrastructure Partners has the right to redeem its interests for cash upon the occurrence of certain events, with a current redemption value as adjusted by the contractually stated distribution amount that is recognized in each reporting period as net income attributable to redeemable stock of subsidiary on the consolidated statements of operations of $ million as of , 2024. See “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Funding, LLC Preferred Units.”

(5)

Represents third-party interests in the Company’s subsidiary, Calcasieu Pass Holdings, LLC, resulting from the issuance of preferred units to a fund associated with Stonepeak Infrastructure Partners. Such units will be, upon the occurrence of certain conditions, redeemed for an agreed price or converted into common units of Calcasieu Pass Holdings, LLC. See “Description of Indebtedness and Project Financing—Project Equity Financing—Calcasieu Pass Holdings, LLC Preferred Units.”

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

DILUTION

If you invest in our Class A common stock in this offering, your ownership interest will be diluted immediately to the extent of the difference between the initial public offering price per share of our Class A common stock and the pro forma as adjusted net tangible book value per share of our Class A common stock immediately after this offering.

We have presented dilution in the pro forma as adjusted net tangible book value per share after this offering assuming that the holder of our Class B common stock had all of its Class B common stock converted to newly issued shares of Class A common stock on a one-for-one basis in order to more meaningfully present the dilutive impact to the investors in this offering. We refer to the assumed conversion of all Class B common stock for shares of Class A common stock as described above in the previous sentence as the “Assumed Conversion.”

Our historical net tangible book value as of was $ billion, or $ per share of our Class A common stock. Our historical net tangible book value is the amount of our total tangible assets less our total liabilities. Historical net tangible book value per share represents historical net tangible book value, divided by the number of outstanding shares of our Class A common stock.

Our pro forma net tangible book value as of was $ billion, or $ per share of Class A common stock. Pro forma net tangible book value per share represents pro forma tangible assets, less pro forma liabilities, divided by the pro forma aggregate number of shares of Class A common stock outstanding, after giving effect to (i) the -for-1 stock split on our Class A common stock to be effected in connection with this offering, immediately prior to the automatic conversion described in (ii); (ii) the automatic conversion of all outstanding shares of our Class A common stock held by VG Partners immediately prior to the completion of this offering into an equal number of shares of our Class B common stock; (iii) the filing and effectiveness of our amended and restated certificate of incorporation, each of (i) and (ii) will occur immediately prior to the completion of this offering; and (iv) the Assumed Conversion.

After giving effect to the sale by us of shares of Class A common stock in this offering, at an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover page of this prospectus), and the receipt and application of the net proceeds after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma as adjusted net tangible book value as of would have been $ , or $ per share. This represents an immediate increase in pro forma as adjusted net tangible book value to existing stockholders of $ per share and an immediate dilution to new investors of $ per share. Dilution per share represents the difference between the price per share to be paid by new investors for the shares of Class A common stock sold in this offering and the pro forma as adjusted net tangible book value per share immediately after this offering. The following table illustrates this per share dilution:


Assumed initial public offering price		$
Historical net tangible book value per share as of	$
Pro forma net tangible book value per share as of
Increase in pro forma as adjusted net tangible book value per share attributable to new investors

Pro forma as adjusted net tangible book value per share after offering

Dilution per share to new investors		$

Each $1.00 increase (decrease) in the assumed initial offering price of $ per share of our Class A common stock would increase (decrease) our pro forma as adjusted net tangible book value at , after deducting estimated underwriting discounts and commissions, by approximately $ million, or

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

approximately $ per share, and the dilution per share to new investors by approximately $ (assuming (i) the number of shares of our Class A common stock offered by us, as set forth on the cover of this prospectus, remains the same, (ii) no exercise of the underwriters’ option to purchase additional shares and (iii) the Assumed Conversion). We may also increase or decrease the number of shares we are offering. An increase of one million shares in the number of shares offered by us would result in pro forma as adjusted net tangible book value at , after deducting estimated underwriting discounts and commissions, of approximately $ million, or $ per share, and the dilution per share to investors in this offering would be $ per share (assuming (i) the public offering price remains the same, (ii) no exercise of the underwriters’ option to purchase additional shares and (iii) the Assumed Conversion). Similarly, a decrease of one million shares in the number of Class A shares of common stock offered by us would result in pro forma as adjusted net tangible book value at , after deducting estimated underwriting discounts and commissions, of approximately $ million, or $ per share, and the dilution per share to investors in this offering would be $ per share (assuming (i) the public offering price remains the same, (ii) no exercise of the underwriters’ option to purchase additional shares and (iii) the Assumed Conversion). The information discussed above is illustrative only and will adjust based on the actual public offering price and other terms of this offering determined at pricing.

The following table sets forth, on a pro forma as adjusted basis, as of , 2024, the number of shares of common stock purchased from us, the total consideration paid, or to be paid, and the average price per share paid, or to be paid, by existing stockholders and by the new investors, at an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover page of this prospectus), before deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us, and gives effect to the Assumed Conversion:

Shares Purchased

Total
Consideration

Average
Price
Per Share

Number

Percent

Amount

Percent

Amount

Existing stockholders

New investors

Total

100

Each $1.00 increase (decrease) in the assumed initial offering price of $ per share of Class A common stock would increase (decrease) the total consideration paid by new investors by approximately $ million, or the percent of total consideration paid by new investors by approximately % (assuming the number of shares of our Class A common stock offered by us, as set forth on the cover of this prospectus, remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares). We may also increase or decrease the number of shares we are offering. An increase (decrease) of shares in the number of one million shares offered by us would increase (decrease) the total consideration paid by new investors by approximately $ million, or the percent of total consideration paid by new investors by approximately % (assuming the public offering price remains the same, and assuming no exercise of the underwriters’ option to purchase additional shares).

After giving effect to the sale of shares in this offering, assuming the underwriters’ option to purchase additional shares is not exercised and after giving effect to the Assumed Conversion, our existing stockholders would own approximately % (or % if the underwriters’ option is exercised in full) and our new investors would own approximately % (or % if the underwriters’ option is exercised in full) of the total number of shares of our Class A common stock outstanding after this offering.

The information discussed above is illustrative only and will adjust based on the actual public offering price and other terms of this offering determined at pricing. The foregoing tables assume no exercise of the underwriters’ option to purchase additional shares or of outstanding stock options after . At , 2024, shares of Class A common stock were subject to outstanding options, at a weighted average exercise price of $ . To the extent these options are exercised, there will be further dilution to new investors.

100

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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 together with our consolidated financial statements, our interim condensed consolidated financial statements and the other financial information appearing elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of various factors, including those discussed below and those discussed in the sections entitled “Risk Factors” and “Forward-Looking Statements” included elsewhere in this prospectus.

Overview

Fundamentals of Our Business

Revenue from LNG sales

We aim to generate revenue primarily from the sale of LNG produced at our facilities, both during the commissioning of each of our projects and after our projects achieve COD.

Our primary source of revenue has been the sale of commissioning cargos at the Calcasieu Project, and we expect that to continue until at least one of our projects becomes fully operational. Although the construction of the Calcasieu Project is substantially complete, the project is currently undergoing a multi-faceted commissioning program to complete the facility’s components, bring them to design specification and establish reliable and safe facility-wide operating conditions in preparation for the commencement of lender-required performance reliability testing. Significant work related to commissioning, carryover completions, rectification, including remedying unexpected challenges with equipment reliability identified during the first-time implementation of our innovative design and configuration, and reliability testing, is ongoing and we believe will need to be completed before certain components operate as intended and the facility can be fully commercially

101

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operable, and COD can occur. As of , 2024, we had received $ billion in gross proceeds ($ billion in net proceeds after deducting net cash paid for natural gas, which primarily includes the net cost of purchasing and transporting feed gas) from such commissioning cargos at the Calcasieu Project. Commissioning cargos are sold to various customers under master SPAs, either as single cargos 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. As a result, the amount of revenue we are able to generate from such sales of commissioning cargos has differed, and will likely continue to differ, from period to period and from project to project, and such differences could be material.

The majority of the nameplate capacity at our Calcasieu Project, Plaquemines Project and Phase 1 of the CP2 Project after they achieve their COD will be sold under long-term 20-year post-COD SPAs, at which point our revenue will primarily depend on the contract prices for the sale of LNG under such post-COD SPAs and the price at which we sell any excess capacity that we produce at our facilities in excess of the relevant nameplate capacity. As of , 2024, we have entered into post-COD SPAs with respect to mtpa of the aggregate expected nameplate capacity for our first three projects of mtpa. The post-COD SPAs cover the entire nameplate capacity of the Calcasieu Project, equivalent to 10.0 mtpa, and the entire nameplate capacity of the Plaquemines Project, equivalent to 20.0 mtpa, with the remaining mtpa covering approximately % of the nameplate capacity of the CP2 Project’s Phase 1, equivalent to 14.4 mtpa. Additionally, mtpa of such mtpa is contracted under 20-year fixed price post-COD SPAs and only mtpa is contracted on a short- or medium-term basis. We aim to market and sell the expected nameplate capacity at our subsequent 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.

After achieving COD for each of our projects, we intend to market and sell any quantities of LNG that are not contractually committed, including any LNG produced above the relevant project’s nameplate capacity, or excess capacity. Such quantities of LNG are expected to be marketed and sold through VG Commodities, a wholly-owned subsidiary, pursuant to certain intercompany SPAs, providing an opportunity to generate additional revenue on an ongoing basis.

Project costs

We have incurred significant project costs, and we expect to continue to incur significant additional costs, in connection with the development, construction and commissioning of our projects prior to the commencement of commercial operations. Project costs include the engineering, procurement and construction costs, as well as owners’ costs and financing costs related to our projects. For details on the risks relating to the cost estimates presented herein, see “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.” The ultimate project costs that we incur will impact our future depreciation expense and interest expense and, as a result, will impact our future gross and operating margins. 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 financing transactions, mezzanine financing and/or other similar financing alternatives). However, the proportion of debt-to-equity funding will depend on various factors, including market conditions and the amount of long-term contracted revenue for the relevant project. 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 CP3 Project, the Delta Project or any future project we may develop will be similar to those used for the Calcasieu Project and Plaquemines Project.

•

Calcasieu Project. As of , 2024, we expect that the remaining project costs to achieve the project completion date for the Calcasieu Project will be funded with cash held in cash reserve accounts pursuant to our project financing arrangements. Such cash is reflected as restricted cash on our balance sheet as of , 2024, and is in an amount we expect to be sufficient to complete the project and achieve COD for the Calcasieu Project.

102

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

Plaquemines Project. As of , 2024, we estimate that the total project costs for the Plaquemines Project will be approximately $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs, of which approximately $ billion had been paid for as of , 2024. We believe we have sufficient project-level cash, borrowing capacity under our existing project-level debt financing, and access to substantial commissioning cargo proceeds to fund the completion of the Plaquemines Project based on our current estimate of the total project costs.

•

CP2 Project. As of , 2024, we estimate that the total project costs for the CP2 Project will be approximately $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs. 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 estimates for the CP2 Project reflect 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. We have not yet raised project-level debt or equity financing for the CP2 Project.

•

CP3 Project and Delta Project. As of , 2024, we estimate that the total project costs for the CP3 Project and the Delta Project will be approximately $ billion and $ billion respectively, in each case including EPC contractor profit and contingency, owners’ costs and financing costs. Given that we have not executed EPC contracts with respect to any portion of the CP3 Project or the Delta Project, and that no substantial construction work has been undertaken on either of those projects to date, these estimates are based upon our construction cost experiences with the Calcasieu Project, the Plaquemines Project and the contracts that we have executed for the CP2 Project. The cost estimates for the CP3 Project and the Delta Project reflect 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 CP3 Project and the Delta 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. We have not yet raised project-level debt or equity financing for the CP3 Project or the Delta Project.

Reorganization Transactions and Historical Financial Statements

In September 2023, we engaged in a series of reorganization transactions, or the Reorganization Transactions, that ultimately resulted in the Company becoming the principal parent company of our entire enterprise. See “Certain Relationships and Related Party Transactions—Reorganization Transactions” for further information. As a result of the Reorganization Transactions, effective as of September 25, 2023, VGLNG, our principal operating company, became a direct, wholly-owned subsidiary of the Company. Additionally, effective as of September 25, 2023, VG Commodities, formerly a wholly-owned subsidiary of Legacy VG Partners, became a wholly-owned subsidiary of the Company and a direct, wholly-owned subsidiary of VGLNG.

The Reorganization Transactions were accounted for as a common control transaction, prior to which the Company had no operations and no assets or liabilities. Accordingly, the financial results and other information included in the Company’s consolidated financial statements and presented in this prospectus for periods prior to consummation of the Reorganization Transactions are reflective of Legacy VG Partners, except for earnings per share, which has been recast to reflect the impact of VGLNG’s historical outstanding shares as if they had been the shares of the Company converted in a one-for-one-exchange. See “Note 1 – The Company” in our annual financial statements included elsewhere in this prospectus for further information.

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Key Factors Affecting Results of Operations

The key factors affecting our results of operations and financial performance are as follows:

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.

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 prospectus. 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:

•

Contract price under our SPAs. Our existing post-COD SPAs will require our export customers to pay us a fixed facility charge 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. The fixed facility charge varies across our post-COD SPAs and a portion of the fixed facility charge will be adjusted for inflation. For any additional post-COD SPAs that we may enter into in the future which include a fixed facility charge, that amount will be based on several factors, including market conditions at the time we enter into the relevant contract. Final terms for any additional post-COD SPAs we may enter into in the future will not be known until those contracts are executed and will impact our future revenue, as well as our operating margins.

•

Henry Hub gas price. As described above, the variable commodity charge under our post-COD SPAs requires our customers to pay 115% or more of the Henry Hub gas price per MMBtu, 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. We anticipate that any additional post-COD SPAs we enter into in the future will similarly require our export customers to pay a similar variable commodity charge. As a result, changes in the Henry Hub gas price will impact our future revenue, as well as our operating margins. In addition, there may be differences, and such differences may be material, between the actual price we pay for feed gas and the Henry Hub gas price used to calculate the variable commodity charges payable by our customers under the relevant post-COD SPAs, which could affect our operating margins.

•

Sales of uncommitted and excess LNG. We intend to market and sell any uncommitted LNG and any excess capacity through VG Commodities, 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.

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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.

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 our CP2 Project, CP3 Project and 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 “Business—Major Consultants and Contractors” 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.

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 our CP3 Project and 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.

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 “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 “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.”

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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. For example, 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 “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, which could, in turn, negatively affect the price of our Class A common stock.”

Financial Operations Overview

Revenue

We have a limited operational history. Although we began generating proceeds from sales of commissioning cargos at the Calcasieu Project in the first quarter of 2022, we did not commence recognizing sales of LNG as revenue in our financial statements until April 2022, with the assets of the Calcasieu Project being placed in service from an accounting perspective between April and August of 2022.

At the Calcasieu Project, significant work related to commissioning, carryover completions, and rectification is currently ongoing and includes remedying unexpected challenges with equipment reliability identified during the first-time implementation of our innovative design and configuration, and reliability testing. We believe such work will need to be completed before certain components operate as intended and the facility can be fully commercially operable, and COD can occur. Given such ongoing work, we are targeting to complete all remediation work and achieve COD in once the project has completed its commissioning process and testing and is capable of safely and reliably producing its designed nameplate levels of LNG volumes. At such time, we expect to commence LNG deliveries under our post-COD SPAs relating to the Calcasieu Project.

We aim to commence production at each of our projects on a sequential basis, with each liquefaction train being brought online as it is commissioned.

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 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 individual molecule of LNG is viewed as a separate performance obligation. 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.

Generally, we recognize sales of LNG as revenue in our financial statements. However, when we produce LNG at our projects prior to the assets of that project being placed in service from an accounting perspective, we recognize the net proceeds from the generation and sale of that LNG as a reduction to the cost basis of construction in progress, in accordance with the applicable accounting guidance. In our financial statements, we

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refer to the LNG produced at our facilities before such assets are placed in service from an accounting perspective as test LNG and the proceeds from their sale as test LNG sales. For the Calcasieu Project, the assets were placed in service from an accounting perspective between April and August 2022. The proceeds from test LNG sales are determined based on estimates of LNG production generated from commissioning activities. The production and sale of test LNG during this period are activities necessary to get the facility ready for its intended use. Test LNG sales are recognized as a reduction to the cost basis of construction and the cost of producing test LNG is recognized as an addition to the cost basis of construction. Once assets are placed in service from an accounting perspective, we then begin recognizing the sales of LNG as revenue in our financial statements.

Operating Expenses

Our operating expenses consist primarily of cost of sales, operating and maintenance expenses, general and administrative expenses, development expenses, and depreciation and amortization.

Cost of Sales

Cost of sales is comprised of the direct cost of producing LNG recognized as revenue. It includes the cost of purchasing and transporting natural gas used to produce LNG, also known as feed gas, and excludes depreciation and amortization shown separately on the consolidated statements of operations.

Under our existing post-COD SPAs and under substantially all of the commissioning cargo sales that have been 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.

Operating and Maintenance Expenses

Operating and maintenance expenses primarily include non-capitalizable costs directly associated with the operation and maintenance of our projects, including personnel costs, the cost of spares and consumables used in maintenance, land lease expense, Asset Retirement Obligation, or ARO, accretion expense, and project-related information technology costs and contractors. We outsource certain major equipment maintenance activities, but our various operating subsidiaries are responsible for performing day-to-day operations and maintenance work for our projects. See “Business—Major Consultants and Contractors” for more information. We anticipate that operating and maintenance expenses will increase significantly as we transition to the commissioning and operation of our projects (as was the case for the Calcasieu Project).

General and Administrative Expenses

General and administrative expenses consist primarily of costs not directly associated with the operations or development of our projects such as our corporate functions including executive management, information technology (except for direct project-related IT costs that are included in operating and maintenance expense), human resources, legal and finance. In addition, we expect that after the completion of this offering, we will incur additional personnel, audit, tax, accounting, legal and other costs related to compliance with applicable securities laws and other regulations, as well as additional insurance, investor relations and other costs associated with being a public company.

Development Expenses

Development expenses consist primarily of costs incurred to develop a project prior to management’s conclusion that construction and completion of that project is probable and that are not otherwise recoverable in

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other projects or for resale as well as construction stage costs that are not capitalizable. These expenses consist primarily of engineering and design expenses and other development related expenses to the extent these costs cannot be capitalized.

The costs incurred to develop our LNG projects are generally treated as development expenses until construction and completion of the relevant project is considered probable by our management. After an LNG project is deemed probable, the costs associated with the development and construction of the liquefaction facility and associated pipeline, including capitalized interest, are recorded as construction in progress, and not an operating expense. In assessing probability, we consider whether: (i) management has committed to funding construction of the LNG project, (ii) financing for the project is available, (iii) the ability exists to meet the necessary local and other governmental regulations, (iv) SPAs with respect to an adequate amount of the expected nameplate capacity of the project have been entered into, and (v) equipment and construction contracts for the project have been secured. In October 2018, we met these criteria with respect to the Calcasieu Project and costs associated with the development and construction of the liquefaction facility and associated pipeline, including capitalized interest, have been recorded on our balance sheet as construction in progress since that date. On March 1, 2022 and June 30, 2022, we met these criteria with respect to Phase 1 and Phase 2 of the Plaquemines Project, respectively, and costs associated with the development and construction of the liquefaction facility and associated pipeline, including capitalized interest, have been recognized on our balance sheet as construction in progress or advanced equipment payments to the extent allowed under the applicable accounting guidance since that date. As of , 2024, we had not met these criteria with respect to the CP2 Project, the CP3 Project, or the Delta Project. The costs incurred to date related to these projects have been capitalized to the extent allowable under GAAP, otherwise they have been, and will continue to be, expensed until such conditions are met. 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. Additionally, we have capitalized payments to landowners for rights-of-way along the proposed pipeline routes, certain leasehold improvement costs necessary for preparing the facilities for their intended use and direct costs of construction-related activities incurred with third parties, including, but not limited to, payments for certain detailed engineering design work and the early procurement of certain long lead-time equipment to the extent allowable under the applicable accounting guidance.

Depreciation and Amortization Expense

Beginning in 2022, with the commencement of operations at the Calcasieu Project, we began to incur depreciation for the property, plant and equipment associated with the assets held by the Calcasieu Project over their estimated useful lives. Prior to 2022, depreciation and amortization had been limited to office equipment and furniture, as well as leasehold improvements to our office spaces and certain marine offloading facilities situated on land we have leased near the Calcasieu Project site land. In the future, as new facilities come online, we expect that our depreciation and amortization expense will increase substantially when these assets are placed in service from an accounting perspective.

Interest Income

Interest income consists primarily of interest income earned on our cash and cash equivalents and investments balances. Our cash and cash equivalents and investments are currently held primarily in cash deposits at federally licensed banks, or short-term, investment-grade, interest-bearing instruments and U.S. government securities. We expect our interest income to fluctuate in the future with changes in average investment balances and market interest rates.

Interest Expense

Interest expense consists primarily of financing fees, interest cost, and commitment fees incurred in connection with our various debt financing transactions, partially offset by capitalized interest. See “—Liquidity and Capital Resources.”

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We anticipate entering into one or more sources of debt and equity financing to fund certain costs for the CP2 Project, the CP3 Project, the Delta Project, our pipeline development projects, and our LNG tankers. We expect to incur significant additional financing fees and interest expense in connection with the anticipated debt financing related to such liquefaction projects, pipeline projects, and tankers. Depending on the timing of the financing, we anticipate capitalizing a portion of the interest costs that we incur while the relevant natural gas liquefaction and export facilities, pipeline projects and LNG tankers are under construction. We generally hedge a substantial portion of our outstanding variable rate debt through the use of interest rate swaps that are marked to market. As of December 31, 2023, we had entered into interest rate swaps targeting a hedge ratio of 97% and 80% of our variable rate debt for the Calcasieu Project and the Plaquemines Project, respectively.

Income Tax Expense

We are a corporation organized in Delaware and, as such, are subject to taxation in the United States. See below for a discussion of income tax expense for the periods presented.

During the year ended December 31, 2022, we determined that sufficient positive evidence existed to support recoverability of our federal deferred tax assets and accordingly released the valuation allowance against our federal deferred tax assets. We continued to maintain a valuation allowance against a portion of our state deferred tax assets, for which we continue to believe the more-likely-than-not recognition threshold has not been met. As of December 31, 2023, we have accumulated federal net operating loss carryforwards of $367 million with an indefinite carryforward period. We additionally had accumulated state net operating loss carryforwards of approximately $1.7 billion (after the application of state apportionment factors), of which $42 million will expire by 2037.

Segments

We have three reportable segments, which consist of the Calcasieu Pass Project, the Plaquemines Project, and the CP2 LNG Project. Each reportable segment includes activity of both the respective liquefaction and export terminal and the associated pipeline that will supply the natural gas to that facility. 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 at this time and therefore are included in Corporate and other.

Our performance is evaluated based on income (loss) from operations. All revenue and the majority of our long-lived assets were attributed to or located in the United States. Certain assets related to our shipping and marketing activities are located outside of the United States.

We loaded our first export cargo from the Calcasieu Project in March 2022. During the years ended December 31, 2023, and 2022, we loaded 144 and 94 cargos, respectively, and received $7.8 billion and $8.2 billion in gross proceeds, respectively, from such sales (or $6.0 billion and $5.6 billion, respectively, in net proceeds after deducting net cash paid for natural gas, which primarily includes the net cost of purchasing and transporting feed gas).

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Results of Operations

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

The following table shows a summary of our results of operations for the periods indicated.


	Years Ended December 31,						Change
	2023			2022			($)			(%)
	($ in millions)
Revenue	$	7,897		$	6,448		$	1,449			22	%

Operating Expense
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,684			2,093			(409	)		(20	)%
Operating and maintenance expense		391			140			251			179	%
General and administrative expense		224			191			33			17	%
Development expense		490			311			179			58	%
Depreciation and amortization		277			158			119			75	%
Insurance recoveries, net		(19	)		—			(19	)		NM

Total operating expense		3,047			2,893			154			5	%

Income from Operations		4,850			3,555			1,295			36	%
Other Income (Expense)
Interest income		172			18			154			NM
Interest expense, net		(641	)		(592	)		(49	)		8	%
Gain on derivatives, net		174			1,212			(1,038	)		(86	)%
Gain (loss) on embedded derivative		—			(14	)		14			NM
Loss on financing transactions		(123	)		(635	)		512			(81	)%

Total other expense		(418	)		(11	)		(407	)		NM

Income before Income Tax Expense		4,432			3,544			888			25	%

Income tax expense		816			447			369			83	%

Net Income	$	3,616		$	3,097		$	519			17	%

NM Percentage not meaningful.

Revenue

Revenue was $7.9 billion for the year ended December 31, 2023, a $1.4 billion, or 22%, increase from $6.4 billion during the year ended December 31, 2022. This increase was primarily due to $7.1 billion from higher LNG sales volumes, partially offset by a decrease of $5.8 billion due to lower net pricing. The Calcasieu Pass Project facilities were in service from an accounting perspective and generating revenue for the entire year ended December 31, 2023, as compared to being placed in service from an accounting perspective on a sequential basis between April and August 2022, and therefore generating revenue for only a portion of the year ended December 31, 2022. The proceeds attributable to test LNG sales generated prior to the Calcasieu Pass Project facilities being in service from an accounting perspective, and therefore recognized as construction in progress and not as revenue, were $1.8 billion for the year ended December 31, 2022.

Operating Expense

Operating expense was $3.0 billion for the year ended December 31, 2023, a $154 million, or 5%, increase from $2.9 billion during the year ended December 31, 2022. This increase was primarily a result of an increase in operating and maintenance expense. Other factors which had a lesser influence were increases in general and administrative expense, development expense, and depreciation and amortization expense. These were partially offset by a decrease in cost of sales and an increase in insurance recoveries, as explained below.

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Cost of Sales

Cost of sales was $1.7 billion for the year ended December 31, 2023, a $409 million, or 20%, decrease from $2.1 billion during the year ended December 31, 2022. This decrease was due to $2.8 billion from lower natural gas prices and higher efficiency, partially offset by an increase of $2.4 billion from higher LNG sales volumes. The Calcasieu Pass Project facilities were in service from an accounting perspective and incurring cost of sales for the entire year ended December 31, 2023, as compared to being placed in service from an accounting perspective on a sequential basis between April and August 2022, and therefore incurring cost of sales for only a portion of the year ended December 31, 2022. The cost attributable to the production of test LNG sales incurred prior to the Calcasieu Pass Project facilities being in service from an accounting perspective, and therefore recognized as construction in progress and not as cost of sales, was $723 million for the year ended December 31, 2022.

Operating and Maintenance Expense

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 Pass 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.

General and Administrative Expense

General and administrative expense was $224 million for the year ended December 31, 2023, a $33 million, or 17%, increase from $191 million during the year ended December 31, 2022. This increase was primarily due to increased personnel costs due to an increase in employee headcount.

Development Expense

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 LNG 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.

Depreciation and Amortization Expense

Depreciation and amortization expense was $277 million for the year ended December 31, 2023, a $119 million, or 75%, increase from $158 million during the year ended December 31, 2022. This increase was primarily due to placing additional property, plant and equipment at the Calcasieu Pass Project in service from an accounting perspective throughout the year ended December 31, 2022.

Insurance Recoveries, net

Insurance recoveries, net were $19 million for the year ended December 31, 2023, a $19 million increase from the year ended December 31, 2022. This increase was mainly due to the recognition of the Company’s portion of insurance claims received in connection with Hurricane Laura storm costs during the year ended December 31, 2023, with no similar activity during the year ended December 31, 2022.

Income from Operations

Income from operations was $4.9 billion for the year ended December 31, 2023, a $1.3 billion, or 36%, increase from $3.6 billion during the year ended December 31, 2022. This increase was primarily a result of higher sales volumes and margin earned from the sale of LNG produced by the Calcasieu Pass Project assets placed in service from an accounting perspective between April and August 2022.

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Other Expense

Other expense was $418 million for the year ended December 31, 2023, a $407 million increase from $11 million during the year ended December 31, 2022. This increase was primarily the result of a decrease in the gain on derivatives, net, as compared to the same period in 2022. Another factor which had a lesser influence was an increase in our interest expense, net as compared to the same period in 2022. These increases in other expense were partially offset by a decrease in our loss on financing transactions, a loss on embedded derivative that did not recur in 2023, and an increase in interest income, as explained below.

Interest Income

Interest income was $172 million for the year ended December 31, 2023, a $154 million increase from $18 million during the year ended December 31, 2022. This increase was primarily due to larger average cash balances and higher interest rates during the year ended December 31, 2023 compared to the year ended December 31, 2022.

Interest Expense, Net

Interest expense, net was $641 million for the year ended December 31, 2023, a $49 million, or 8%, increase from $592 million during the year ended December 31, 2022. This increase was primarily due to higher interest costs associated with increased debt outstanding and higher interest rates. These increases were partially offset by higher capitalized interest, primarily at the Plaquemines Project and Corporate, as a result of more interest meeting the threshold for capitalization, partially offset by a reduction in capitalized interest at the Calcasieu Pass Project due to the assets being placed in service from an accounting perspective in 2022.

Gain on Derivatives, Net

Gain on derivatives, net was $174 million for the year ended December 31, 2023, a $1.0 billion, or 86%, decrease from $1.2 billion during the year ended December 31, 2022. This decrease was primarily due to a reduction in the gain on the Plaquemines Project interest rate swaps of $838 million, due to smaller changes in the forward interest rate curves over higher notional, and a reduction in the gain on the Calcasieu Pass Project interest rate swaps of $197 million, due to smaller changes in the forward interest rate curves over lower notional during the year ended December 31, 2023 compared to the year ended December 31, 2022.

Loss on Embedded Derivative

Loss on embedded derivative was nil for the year ended December 31, 2023, a $14 million decrease from the loss of $14 million during the year ended December 31, 2022. This decrease was due to the full prepayment of the 2024 Convertible Note in December 2022, with no corresponding change in the fair value of embedded derivatives during the same period in 2023.

Loss on Financing Transactions

Loss on financing transactions was $123 million for the year ended December 31, 2023, a $512 million, or 81%, decrease from $635 million during the year ended December 31, 2022. This decrease was primarily due to the write-off of debt issuance costs associated with the prepayment of our three year $500 million senior secured term loan facility due August 2025, or the VGLNG Corporate 2025 Term Loan, and the partial prepayments of our senior secured credit facilities for the Calcasieu Project, or the Calcasieu Pass Credit Facilities, and the equity bridge credit facilities for the Plaquemines Project, or the Plaquemines Equity Bridge Facility, during the year ended December 31, 2023, compared to the write-off of debt issuance costs associated with the prepayment of the convertible notes due 2024, or the 2024 Convertible Notes, the refinancing of the VGLNG Corporate 2025 Term Loan, and the reduction and repayment of debt associated with the Plaquemines Project during the year ended December 31, 2022.

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Income before Income Tax Expense

Income before income tax expense was $4.4 billion for the year ended December 31, 2023, a $888 million, or 25%, increase from $3.5 billion during the year ended December 31, 2022. The increase was primarily a result of the increase in our income from operations.

Income Tax Expense

Income tax expense was $816 million for the year ended December 31, 2023, a $369 million, or 83%, increase from $447 million during the year ended December 31, 2022. Our effective tax rate was 18.4% for the year ended December 31, 2023 compared to 12.5% for the year ended December 31, 2022. The 2023 effective tax rate was impacted by income tax benefits related to the foreign derived intangible income, or FDII, deduction and other permanent GAAP to tax differences. The 2022 effective tax rate was impacted by an income tax benefit from the release of a significant portion of our valuation allowance. This tax benefit was partially offset by tax expense related to the disallowed interest expense and disallowed losses from the prepayment of the 2024 Convertible Note.

Net Income

Net income was $3.6 billion for the year ended December 31, 2023, a $519 million, or 17%, increase from $3.1 billion during the year ended December 31, 2022. This increase was primarily a result of an increase in income from operations due to higher revenue, partially offset by cost of sales, from the sale of LNG produced by the Calcasieu Pass Project partially offset by an increase in income tax expense and a decrease in gain on derivatives, net, as explained above.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

The following table shows a summary of our results of operations for the periods indicated.


	Years Ended December 31,						Change
	2022			2021			($)			(%)
	($ in millions)
Revenue	$	6,448		$	—		$	6,448			NM
Operating Expense
Cost of sales (exclusive of depreciation and amortization shown separately below)		2,093			—			2,093			NM
Operating and maintenance expense		140			58			82			141	%
General and administrative expense		191			89			102			115	%
Development expense		311			188			123			65	%
Depreciation and amortization		158			6			152			NM
Insurance recoveries, net		—			(4	)		4			(100	)%

Total operating expense		2,893			337			2,556			NM

Income (Loss) from Operations		3,555			(337	)		3,892			NM
Other Income (Expense)
Interest income		18			—			18			NM
Interest expense, net		(592	)		(52	)		(540	)		NM
Gain on derivatives, net		1,212			38			1,174			NM
Gain (loss) on embedded derivative		(14	)		12			(26	)		NM
Loss on financing transactions		(635	)		(97	)		(538	)		NM

Total other expense		(11	)		(99	)		88			(89	)%

Income (Loss) before Income Tax Expense		3,544			(436	)		3,980			NM
Income tax expense		447			—			447			NM

Net Income (Loss)	$	3,097		$	(436	)	$	3,533			NM

NM Percentage not meaningful.

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Revenue

Revenue was $6.4 billion for the year ended December 31, 2022, a $6.4 billion increase from the year ended December 31, 2021, during which there was no revenue. This increase was due to the sale of the commissioning cargos produced by the Calcasieu Pass Project assets that were placed in service from an accounting perspective between April and August 2022. We recognized no revenue in the prior period because there were no sales of commissioning cargos.

Operating Expense

Operating expense was $2.9 billion for the year ended December 31, 2022, a $2.6 billion increase from $337 million for the year ended December 31, 2021. The increase was primarily a result of an increase in cost of sales, compared to no cost of sales incurred for the year ended December 31, 2021. Other factors which had a lesser influence were increases in depreciation and amortization expense, development expense, operating and maintenance expense, general and administrative expense, and a decrease in insurance recoveries, net of loss from hurricane, as explained below.

Cost of Sales

Cost of sales was $2.1 billion for the year ended December 31, 2022, a $2.1 billion increase from the year ended December 31, 2021, during which we incurred no cost of sales. This increase was largely for the purchase of natural gas due to the sale of commissioning cargos produced by the Calcasieu Pass Project assets that were placed in service from an accounting perspective between April and August 2022. We incurred no cost of sales in the prior period because there were no sales of commissioning cargos.

Operating and Maintenance Expense

Operating and maintenance expense was $140 million for the year ended December 31, 2022, a $82 million, or 141%, increase from $58 million for the year ended December 31, 2021. This increase was due primarily to higher operating costs, including external services, personnel costs, insurance, materials and IT costs in support of LNG production at the Calcasieu Pass Project, during the year ended December 31, 2022, compared to lower pre-production operational support during 2021, a portion of which was capitalized.

General and Administrative Expense

General and administrative expense was $191 million for the year ended December 31, 2022, a $102 million, or 115%, increase from $89 million for the year ended December 31, 2021. The increase was primarily due to increased compensation costs and, to a lesser extent, employee headcount, and higher consulting fees.

Development Expense

Development expense was $311 million for the year ended December 31, 2022, a $123 million, or 65%, increase from $188 million for the year ended December 31, 2021. This increase was primarily due to an increase in early construction-related activity at the Plaquemines Project prior to the project being deemed probable, higher engineering and environmental costs at the CP2 LNG Project, and a fee to secure future construction capacity incurred in 2022.

Depreciation and Amortization

Depreciation and amortization expense was $158 million for the year ended December 31, 2022, a $152 million increase from $6 million for the year ended December 31, 2021. This increase was mainly attributable to placing $6.8 billion of property, plant and equipment at the Calcasieu Pass Project in service from an accounting perspective during 2022.

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Insurance Recoveries, Net

Insurance recoveries, net were nil for the year ended December 31, 2022, a $4 million, or 100%, decrease from a recovery of $4 million for the year ended December 31, 2021. This decrease was mainly due to our portion of insurance recoveries for Hurricane Laura received in 2021.

Income (Loss) from Operations

Income from operations was $3.6 billion for the year ended December 31, 2022, a $3.9 billion increase from our loss from operations of $337 million for the year ended December 31, 2021. This increase was primarily a result of the increase in revenue, partially offset by cost of sales, from to the sale of LNG produced by the Calcasieu Pass Project assets placed in service from an accounting perspective between April and August 2022.

Other Expense

Other expense was $11 million for the year ended December 31, 2022, a $88 million, or 89%, decrease from $99 million for the year ended December 31, 2021. This decrease was primarily a result of an increase in the gain on derivatives, compared to the same period in 2021. Another factor which had a lesser influence was an increase in interest income, compared to the same period in 2021. These increases were partially offset by an increase in loss on financing transactions, an increase in interest expense, net, and an unfavorable change in the gain (loss) on embedded derivative, as explained below.

Interest Income

Interest income was $18 million for the year ended December 31, 2022, a $18 million increase from nil for the year ended December 31, 2021. This increase was primarily due to higher average cash balances during the year ended December 31, 2022, compared to the year ended December 31, 2021.

Interest Expense, Net

Interest expense, net was $592 million for the year ended December 31, 2022, a $540 million increase from $52 million for the year ended December 31, 2021. This increase was primarily due to an increase in non-capitalizable interest of $210 million in Corporate and other, $165 million at the Calcasieu Pass Project, and $92 million at the Plaquemines Project as a result of higher debt balances and less interest that met the threshold for capitalization, as well as an increase in commitment fees of $72 million primarily associated with undrawn commitments supporting the Plaquemines Project.

Gain on Derivatives, Net

Gain on derivatives, net was $1.2 billion for the year ended December 31, 2022, a $1.2 billion increase from $38 million for the year ended December 31, 2021. This increase was primarily due to an increase in the gain on interest rate swaps held by the Plaquemines Project of $1.1 billion, which were executed in the fourth quarter of 2021 and the first half of 2022, due to favorable changes in the forward SOFR curve and the expiration of the FID contingency and an increase in the gain on interest rate swaps held by the Calcasieu Pass Project of $99 million, due to favorable changes in the forward LIBOR curve during the year ended December 31, 2022, compared to the same period in 2021.

Gain (Loss) on Embedded Derivative

Loss on embedded derivative was $14 million for the year ended December 31, 2022, a $26 million decrease from a gain on embedded derivative of $12 million for the year ended December 31, 2021. This decrease was mainly due to an increase in the fair value of the embedded derivative liability during the year ended December 31, 2022, compared to a decrease in the fair value of the embedded derivative liability in the same period in 2021.

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Loss on Financing Transactions

Loss on financing transactions was $635 million for the year ended December 31, 2022, a $538 million increase from $97 million for the year ended December 31, 2021. This increase was primarily due to a loss of $411 million resulting from the prepayment of the 2024 Convertible Notes, a loss of $159 million due to the write off of deferred issuance costs associated with the repayment of the two-year secured credit facility entered into by Plaquemines LNG Holdings, LLC, or PL Holdings, in May 2022 for Phase 1 of the Plaquemines Project, or the PL Holdings Credit Facility, the extinguishment of the two-year secured backstop credit facility entered into by Plaquemines LNG Funding, LLC in May 2022, or the PL Funding Backstop Facility, and the repayment of the bridge loan facility entered into in November 2021 by PL Holdings, or the Plaquemines Bridge Loan Facility, and a loss of $64 million due to the refinancing of the senior secured term loan facility entered into by VGLNG due 2024, or the VGLNG Corporate 2024 Term Loan, and the VGLNG Corporate 2025 Term Loan, compared to a loss of $97 million during the year ended December 31, 2021 primarily due to the write-off of deferred issuance costs associated with the partial termination of the Calcasieu Pass Credit Facilities.

Income (Loss) before Income Tax Expense

Income before income tax expense was $3.5 billion for the year ended December 31, 2022, a $4.0 billion increase from a loss before income tax expense of $436 million for the year ended December 31, 2021. The increase in our income (loss) before income tax expense was primarily a result of the increase in our income from operations.

Income Tax Expense

Income tax expense was $447 million for the year ended December 31, 2022, a $447 million increase from nil for the year ended December 31, 2021. This increase was primarily due to the recognition of income tax expense from operations of $714 million and permanent tax differences associated with the 2024 Convertible Notes of $151 million, partially offset by a $416 million income tax benefit related to the release of a significant portion of the valuation allowance on U.S. federal deferred tax assets during the year ended December 31, 2022.

Net Income (Loss)

Net income was $3.1 billion for the year ended December 31, 2022, a $3.5 billion increase from our net loss of $436 million for the year ended December 31, 2021. The increase was primarily a result of an increase in our income (loss) before income tax expense, which was partially offset by an increase in income tax expense of $447 million as discussed above.

Segment Results of Operations

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Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

The following table shows a summary of our segment income (loss) from operations for the periods indicated:


	Years Ended December 31,						Change
	2023			2022			($)			(%)
	($ in millions)
Income (loss) from operations:
Calcasieu Pass Project	$	5,598		$	4,042		$	1,556			38	%
Plaquemines Project		(187	)		(269	)		82			(30	)%
CP2 LNG Project		(362	)		(34	)		(328	)		NM
Corporate and other⁽¹⁾		(199	)		(184	)		(15	)		8	%

Total	$	4,850		$	3,555		$	1,295			36	%

(1)	Includes costs associated with the CP3 Project, the Delta Project, certain other development stage projects, our shipping business and certain corporate activities.

Calcasieu Pass Project

For the year ended December 31, 2023, our Calcasieu Pass Project had income from operations of $5.6 billion, a $1.6 billion, or 38%, increase from $4.0 billion during the year ended December 31, 2022. This increase was primarily due to:

•

an increase in revenue of $1.4 billion primarily due to $7.1 billion from higher LNG sales volumes, partially offset by a decrease of $5.8 billion due to lower net pricing. The Calcasieu Pass Project facilities were in service from an accounting perspective and generating revenue for the entire year ended December 31, 2023, as compared to being placed in service from an accounting perspective on a sequential basis between April and August 2022, and therefore generating revenue for only a portion of the year ended December 31, 2022. The proceeds attributable to test LNG sales generated prior to the Calcasieu Pass Project facilities being in service from an accounting perspective, and therefore recognized as construction in progress and not revenue, were $1.8 billion for the year ended December 31, 2022; and

•

a decrease in cost of sales of $409 million due to $2.8 billion from lower natural gas prices and higher efficiency, partially offset by an increase of $2.4 billion from higher LNG sales volumes. The Calcasieu Pass Project facilities were in service from an accounting perspective and incurring cost of sales for the entire year ended December 31, 2023, as compared to being placed in service from an accounting perspective on a sequential basis between April and August 2022, and therefore incurring cost of sales for only a portion of the year ended December 31, 2022. The cost attributable to the production of test LNG sales incurred prior to the Calcasieu Pass Project facilities being in service from an accounting perspective, and therefore recognized as construction in progress and not cost of sales, was $723 million for the year ended December 31, 2022.

These net favorable changes were partially offset by:

•

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

•

an increase in depreciation and amortization expense of $112 million, primarily due to placing additional property, plant and equipment at the Calcasieu Pass Project in service from an accounting perspective throughout the year ended December 31, 2022.

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Plaquemines Project

For the year ended December 31, 2023, our Plaquemines Project had a loss from operations of $187 million, a $82 million, or 30%, decrease from $269 million during the year ended December 31, 2022. This decrease was primarily due to a decrease in development expense of $184 million due to the Plaquemines Project being deemed probable in March 2022, and the costs to develop and construct the facility largely being capitalized in 2023. This decrease was partially offset by an increase in operating and maintenance expense of $64 million due to higher operating costs primarily due to an increase in non-capitalizable personnel costs and ARO accretion and an increase in general and administrative expenses of $37 million due to higher costs for administrative services.

CP2 LNG Project

For the year ended December 31, 2023, our CP2 LNG Project had a loss from operations of $362 million, a $328 million increase from $34 million during the year ended December 31, 2022. This increase was primarily driven by an increase in development expense of $328 million primarily due to early development, pre-construction and personnel costs related to the CP2 LNG Project that were not capitalizable.

Corporate and other

For the year ended December 31, 2023, Corporate and other had a loss from operations of $199 million, a $15 million, or 8%, increase from $184 million during the year ended December 31, 2022. This increase was primarily driven by an increase in development expense of $14 million, primarily due to an increase in costs related to a Corporate development project, partially offset by a lower fee to secure future construction capacity during the year ended December 31, 2023.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

The following table shows a summary of our segment income (loss) from operations for the periods indicated:


	Years Ended December 31,						Change
	2022			2021			($)			(%)
	($ in millions)
Income (loss) from operations:
Calcasieu Pass Project	$	4,042		$	(85	)	$	4,127			NM
Plaquemines Project		(269	)		(158	)		(111	)		70	%
CP2 LNG Project		(34	)		(15	)		(19	)		127	%
Corporate and other⁽¹⁾		(184	)		(79	)		(105	)		133	%

Total	$	3,555		$	(337	)	$	3,892			NM

(1)	Includes costs associated with the CP3 Project, the Delta Project, certain other development stage projects, our shipping business and certain corporate activities.

Calcasieu Pass Project

For the year ended December 31, 2022, our Calcasieu Pass Project had income from operations of $4.0 billion, which represented a $4.1 billion favorable change from a loss from operations of $85 million for the year ended December 31, 2021. This increase was primarily driven by an increase in revenue of $6.4 billion due to the sale of LNG produced by the Calcasieu Pass Project assets that were placed in service from an accounting perspective between April and August 2022, compared to no revenue generated for the corresponding period in 2021. This increase was partially offset by an increase in the cost of sales (largely from the purchase of natural gas) of $2.1 billion, due to the sale of LNG produced by Calcasieu Pass Project assets that were placed in service from an accounting perspective, compared to no cost of sales for the corresponding period in 2021. Other factors which had a lesser influence were an increase in depreciation and amortization expense of $142 million, which was mainly attributable to placing $6.8 billion of property, plant and equipment in service from an accounting

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perspective during 2022 and an increase in operating and maintenance expense of $73 million, primarily due to higher operating costs, including insurance, external services, personnel costs, materials, and IT costs in support of LNG production during the year ended December 31, 2022, compared to lower pre-production operational support, a portion of which was capitalized during year ended December 31, 2021.

Plaquemines Project

For the year ended December 31, 2022, our Plaquemines Project had a loss from operations of $269 million which represented a $111 million, or 70%, increase from $158 million for the year ended December 31, 2021. This increase was primarily the result of higher development expense of $76 million due to increased development and construction-related activities during the period when the project was not yet deemed probable as well as an increase in general and administrative expenses of $19 million as a result of higher costs for administrative services.

CP2 LNG Project

For the year ended December 31, 2022, our CP2 LNG Project had a loss from operations of $34 million, which represented a $19 million, or 127%, increase from $15 million for the year ended December 31, 2021. This increase was the result of higher development expense of $20 million, primarily due to engineering and environmental costs related to the CP2 LNG Project during the year ended December 31, 2022.

Corporate and other

For the year ended December 31, 2022, Corporate and other had a loss from operations of $184 million, which represented a $105 million, or 133%, increase from $79 million for the year ended December 31, 2021. This increase was the result of higher development expense of $19 million, primarily due to a fee to secure future manufacturing capacity as well as an increase in general and administrative expense of $84 million, mainly resulting from increased compensation costs and, to a lesser extent, employee headcount, and higher consulting fees during the year ended December 31, 2022.

Liquidity and Capital Resources

General

We have a limited operational history and we did not generate any revenue 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.

Funding Requirements

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

As of , 2024, we expect that the remaining project costs to achieve COD for the Calcasieu Project will be funded with cash held in cash reserve accounts pursuant to our project financing arrangements and reflected as restricted cash in our financial statements at the Calcasieu Project in an amount expected to be necessary to complete the project and achieve COD under the Calcasieu Foundation SPAs. For the Calcasieu Project, we obtained approximately $6.6 billion of project-level debt financing and $1.3 billion of equity financing for its construction and development.

As of , 2024, we estimate that the total project costs for the Plaquemines Project will be approximately $ billion, including EPC contractor profit and contingency, owners’ costs and financing

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costs, of which approximately $ billion had been paid for as of , 2024. For the Plaquemines Project, we have obtained approximately $15.0 billion of project-level debt financing comprised of an approximately $12.9 billion term loan facility and $2.1 billion working capital revolving facility, and have made an aggregate of approximately $ billion of equity contributions. As of , 2024, approximately $ billion of such project-level debt financing was outstanding, and we had additional available borrowing capacity of approximately $ billion thereunder. We believe we have sufficient project-level cash, borrowing capacity under our existing project-level debt financing, and access to substantial commissioning cargo proceeds to fund the completion of the Plaquemines Project based on our current estimate of the total project costs.

As of , 2024, we estimate that the total project costs for the CP2 Project will be approximately $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs. 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 “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.”

As of , 2024, we estimate that the total project costs for the CP3 Project and the Delta Project will be approximately $ billion and $ billion, respectively, in each case including EPC contractor profit and contingency, owners’ costs and financing costs. Given that we have not executed EPC contracts with respect to any portion of the CP3 Project or any portion of the Delta Project, and that no substantial construction work has been undertaken on either of those projects to date, these estimates are based upon our construction cost experiences with the Calcasieu Project, the Plaquemines Project, and the contracts that we have executed for the CP2 Project. The cost estimates for the CP3 Project and the Delta Project reflect 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 CP3 Project and the Delta 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 “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.” As of , 2024, no financing (equity nor debt) has been obtained for the CP2 Project, the CP3 Project, or the Delta Project.

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 liquefaction 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 Plaquemines Project.

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We have significant interest expense obligations and anticipate incurring significant financing fees and interest expense in connection with any additional financing for the CP2 Project, the CP3 Project, the Delta Project, our pipeline development projects, our LNG tankers, and any bolt-on expansions or future LNG liquefaction projects. We anticipate capitalizing the interest costs that we incur while the relevant natural gas liquefaction and export facilities or LNG tankers are under construction.

We believe that our current cash and cash equivalents, borrowing capacity under our existing credit facilities, the expected proceeds from sales of LNG at our projects and the net proceeds from this offering 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 and our expected pre-FID capital expenditures with respect to the CP2 Project, the CP3 Project and the Delta Project. However, we anticipate that we will need substantial additional debt and equity capital to commence full construction activities and achieve COD for the CP2 Project, the CP3 Project and the Delta Project. 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 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 the CP2 Project, the CP3 Project and the Delta Project, 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 “Risk Factors.”

Sources and Uses of Cash

Since our inception, we have funded our operations and capital expenditures with various forms of financing, including private placements of equity securities, project equity financings and borrowings at VGLNG and our project entities. As of , 2024, we had raised an aggregate of approximately $ billion of capital. The primary use of our capital resources to date has been to fund expenses related to the development, construction, commissioning and operation of our projects and our other key, complementary assets. This includes the engineering and design work, construction and commissioning of the Calcasieu Project, construction of the Plaquemines Project, procurement for the CP2 Project, repair work on marine offloading facilities, the preparation of all necessary filings with FERC and other regulatory agencies, procuring gas transportation and supply for our projects, building our LNG tanker fleet, procuring regasification capacity, general and administrative expenses, legal expenses, health, safety and environmental engineering expenses, management fees to our affiliate, share repurchases, lease option payments or lease payments for our project sites, servitude and rights-of-way payments for our pipeline and other development-related expenses.

We expect to commence production at our facilities on a sequential basis, with each liquefaction train being brought online as it is commissioned. On March 1, 2022, we announced the successful loading and departure of our first cargo of LNG at the Calcasieu Project and all 18 liquefaction trains at the Calcasieu Project were

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capable of producing initial quantities of LNG by June 2022. As of , 2024, we had loaded and sold LNG commissioning cargos and earned $ billion in gross proceeds from such sales. The primary use of the proceeds from such sales has been to retire existing indebtedness and to fund our projects and our other key, complementary assets.

Private Placement of VGLNG Equity Securities

Since our inception in March 2013, VGLNG has issued shares of its Series A common stock, Series B common stock and Series C common stock for aggregate net proceeds, after deducting fees and expenses, of $796 million.

Repurchases of Equity Securities

Since our inception in March 2013, and up until the Reorganization Transactions, VGLNG repurchased a total of 165,596 shares of its Series B common stock and Series C common stock for $3.0 billion. We may repurchase our capital stock from time to time. Any future determination relating to repurchases of capital stock will be made by our board of directors and will depend on a number of factors, including: our actual and projected financial condition, liquidity and results of operations; our capital levels and needs; tax considerations; any acquisitions or potential acquisitions that we may examine; statutory and regulatory prohibitions and other limitations; the terms of our existing and future indebtedness that restrict the amount of cash that we can apply to pay dividends or repurchase equity; general economic conditions; and other factors deemed relevant by the board of directors.

Credit Agreements

In February 2021, VGLNG entered into the $500 million VGLNG Corporate 2024 Term Loan. Proceeds from the issuance were used to prepay in full a previously outstanding $220 million senior secured term loan, including accrued interest, in order to fund pre-FID construction activities at the Plaquemines Project, as well as for general corporate purposes. In July 2022, VGLNG prepaid $250 million of principal outstanding under the VGLNG Corporate 2024 Term Loan.

In August 2022, VGLNG entered into the $500 million VGLNG Corporate 2025 Term Loan. Proceeds from the issuance were used to prepay the VGLNG Corporate 2024 Term Loan in full (including accrued interest and debt issuance costs). The VGLNG Corporate 2025 Term Loan accrued interest at either the adjusted term SOFR or base rate, plus an applicable margin.

In December 2022, VGLNG amended the VGLNG Corporate 2025 Term Loan to increase the total debt outstanding by $2.8 billion to a total of $3.3 billion. Proceeds from the additional borrowings were used to prepay the 2024 Convertible Notes (described below) and repurchase $1.4 billion of Series B common stock and Series C common stock shares. The remaining net proceeds were intended to be used for general corporate purposes, including to pay for certain project costs.

During the year ended December 31, 2023, we fully prepaid the $3.3 billion of principal outstanding under the VGLNG Corporate 2025 Term Loan. The prepayments were accounted for as extinguishments of the VGLNG Corporate 2025 Term Loan, resulting in a $65 million loss on financing transactions during the year ended December 31, 2023.

VG Commodities Term Loan

In August 2021, we entered into a $216 million three-year senior secured term loan facility due August 2024, or the VG Commodities Credit Agreement. Proceeds from the loans thereunder, or the VG Commodities

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Term Loan, were used by Legacy VG Partners to purchase certain common stock of VGLNG and for general corporate purposes. In October 2021, June 2022, and September 2023 the VG Commodities Credit Agreement was amended to incur $256 million of incremental loans in the aggregate, the proceeds of which were used for general corporate purposes, certain investments, certain distributions, and to repay certain existing debt.

In October 2023, we fully prepaid the $549 million of principal outstanding, which included certain paid-in-kind interest, under the VG Commodities Credit Agreement with a portion of the proceeds from the issuance of the VGLNG 2029 Notes and the VGLNG 2032 Notes (as defined below). The prepayments were accounted for as extinguishments of the VG Commodities Credit Agreement, resulting in a $3 million loss on financing transactions during the year ended December 31, 2023.

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 $2.50 billion aggregate principal amount of 9.500% Senior Secured Notes due 2029, or the VGLNG 2029 Notes, and $1.50 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 7.00% Senior Secured Notes due 2030, or the VGLNG 2030 Notes. The VGLNG 2030 Notes bear interest at a rate of 7.00% 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 or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project, or any related pipeline.

2024 Convertible Notes

In June 2019, VGLNG issued an aggregate of $460 million initial principal amount of the 2024 Convertible Notes. In December 2022, the 2024 Convertible Notes were prepaid in full.

Project Debt and Equity Financing

In August 2019, our subsidiary, VGCP closed a $5.8 billion senior secured construction and term loan facility and a senior secured working capital facility, or collectively, the Calcasieu Pass Credit Facilities, with a group of lenders to fund the costs of developing, constructing and commissioning the Calcasieu Project. The Calcasieu Pass Credit Facilities have a final maturity date of August 19, 2026, and bear interest at SOFR plus an applicable margin. See “Description of Indebtedness and Project Financing—Project Debt Financing—Calcasieu Project—Calcasieu Pass Credit Facilities.”

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In May 2019, our subsidiaries entered into two unit purchase agreements with certain funds associated with Stonepeak Infrastructure Partners, pursuant to which Calcasieu Funding and Calcasieu Holdings, both of which are our subsidiaries, 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 construction costs for the Calcasieu Project. See “Description of Indebtedness and Project Financing—Project Equity Financing.”

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 from these issuances were used to prepay $4.2 billion outstanding under the Calcasieu Pass Credit Facilities and pay fees and expenses in connection with the offering. See “Description of Indebtedness and Project Financing—Project Debt Financing—Calcasieu Project—VGCP Senior Secured Notes.” As of December 31, 2023, December 31, 2022 and December 31, 2021, $4.75 billion, $3.75 billion and $3.75 billion, respectively, were outstanding under the VGCP Senior Secured Notes.

In September 2021, VGCP upsized the working capital facility under the Calcasieu Pass Credit Facilities by an incremental $255 million to $555 million.

In November 2021, VGPL, as borrower, and Gator Express, as guarantor, entered into a $1.0 billion bridge loan credit facility due November 2023, or the Plaquemines Bridge Loan Facility, which was upsized to $1.4 billion in March 2022 and prepaid in May 2022. The net proceeds from the Plaquemines Bridge Loan Facility were used to fund development and construction of the Plaquemines Project prior to closing of the full project financing for Phase 1 of the Plaquemines Project.

In May 2022, VGPL, as borrower, and VGGE, as guarantor, obtained approximately $9.6 billion in project financing (consisting of an approximately $8.5 billion term loan facility and a $1.1 billion working capital revolving facility) that matures in May 2029, to fund the development and construction of Phase 1 of the Plaquemines Project. In addition, PL Funding and PL Holdings entered into two separate equity bridge credit facilities – a $2.1 billion facility, or the PL Funding Backstop Facility and a $1.45 billion facility (which was upsized by an incremental $400 million in July 2022), or the PL Holdings Credit Facility, both of which were repaid in full in 2022. A portion of the proceeds from the project financing was used to prepay the Plaquemines Bridge Loan Facility and pay fees and expenses incurred in connection with the project financing. 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 project financing facilities, or the Plaquemines Credit Facilities, are comprised of an approximately $12.9 billion term loan facility and a $2.1 billion working capital revolving facility. In connection with the upsize, PL Holdings entered into the Plaquemines Equity Bridge Facility, a new approximately $1.7 billion secured credit facility equity bridge credit facility to fund a portion of project costs for the Plaquemines Project. The remaining proceeds from the project financing and the outstanding PL Holdings financing will be used to fund the costs of financing, developing, constructing, and commissioning 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.

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For further information on the foregoing financings, see “Description of Indebtedness and Project Financing.”

Cash Flows

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

The following table shows a summary of our cash flows for the periods indicated:


	Years Ended December 31,						Change
	2023			2022			($)			(%)
	($ in millions)
Net cash from operating activities	$	4,550		$	3,702		$	848			23	%
Net cash used by investing activities		(8,725	)		(2,900	)		(5,825	)		201	%
Net cash from financing activities		7,635			235			7,400			NM

Operating Activities

Net cash from operating activities was $4.6 billion during the year ended December 31, 2023, a $848 million, or 23%, increase from $3.7 billion during the year ended December 31, 2022. The net increase in cash inflows was primarily due to:

•

an increase of $1.4 billion of cash proceeds received from test LNG sales produced by the Calcasieu Pass Project assets that were placed in service from an accounting perspective between April and August 2022;

•

a $208 million favorable change in cash from the settlement of interest rate swaps due to $203 million in net cash received during the year ended December 31, 2023 as compared to $5 million net cash paid to settle interest rate swaps during the year ended December 31, 2022; and

•

an increase of $149 million of cash received from interest income due to larger average cash balances and higher interest rates during the year ended December 31, 2023 as compared to the year ended December 31, 2022.

These increases in cash inflows were partially offset by:

•

an increase of $610 million of cash paid for operating expenses primarily due to an increase in development and pre-construction activities related to the CP2 LNG Project that were not capitalizable and operating activities related to the Calcasieu Pass Project, partially offset by a decrease in development activities related to the Plaquemines Project primarily due to it being deemed probable in March 2022, and the costs to develop the facility subsequently being capitalized;

•

a net increase of $138 million of cash paid for non-capitalized interest and commitment fees comprised of $129 million at the Calcasieu Pass Project and $18 million at Corporate and other, offset by a decrease of $10 million at the Plaquemines Project; and

•

an increase of $128 million of cash paid for income taxes with no similar material activity during the year ended December 31, 2022.

Investing Activities

Net cash used by investing activities was $8.7 billion during the year ended December 31, 2023, a $5.8 billion, or 201%, increase from $2.9 billion during the year ended December 31, 2022. The net increase in cash outflows was primarily due to:

•

an increase in cash used for purchases of property, plant and equipment of $3.5 billion related to:

•

an increase in cash paid for construction of the Plaquemines Project of $3.5 billion for costs incurred after the project was deemed probable in March of 2022;

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•

an increase of $915 million primarily due to advanced equipment payments related to the CP2 LNG Project; and

•

an increase of $600 million due to advanced equipment payments and capitalized interest payments at Corporate and other.

These increases were partially offset by a decrease at the Calcasieu Pass Project of $1.6 billion since assets were placed in service from an accounting perspective in 2022;

•

a decrease in cash proceeds of $1.8 billion from test LNG sales, which was offset against construction in progress, during the year ended December 31, 2022, with no similar cash inflows during the year ended December 31, 2023; and

•

an increase in cash outflows of $539 million to purchase equity investments in Project Kagami 1 Limited and Project Kagami 2 Limited, or together, the Kagami Companies, and Astra 5 Limited and Astra 8 Limited, or together, the Astra Companies, for the ultimate acquisition of four LNG tankers.

Financing Activities

Net cash from financing activities was $7.6 billion during the year ended December 31, 2023, a $7.4 billion increase from $235 million during the year ended December 31, 2022. The net increase in cash inflows was primarily due to:

•

an increase in proceeds from the issuance of debt of $6.3 billion due to $12.3 billion of proceeds from debt issuances during the year ended December 31, 2023, comprised primarily of:

•

proceeds of $9.5 billion from the issuance of the VGLNG Senior Secured Notes;

•

proceeds of $1.7 billion from the issuance of the Plaquemines Equity Bridge Facility in connection with FID for Phase 2 of the Plaquemines Project;

•

proceeds of $1.0 billion from the issuance of the 2030 VGCP Senior Secured Notes; and

•

proceeds of $115 million from the upsizing of the VG Commodities Term Loan.

These compare to $6.0 billion of proceeds from debt issuances during the year ended December 31, 2022, comprised primarily of:

•

proceeds of $3.2 billion due to the refinancing of the VGLNG Corporate 2025 Term Loan;

•

proceeds of $2.4 billion from debt associated with the Plaquemines Project;

•

an increase in proceeds from the project credit facilities of $2.2 billion due to an increase in proceeds from the Plaquemines Credit Facilities of $2.8 billion, partially offset by a decrease in proceeds from the Calcasieu Pass Credit Facilities of $626 million; and

•

a decrease in payments of financing and debt issuance costs of $295 million due to $591 million of payments during the year ended December 31, 2023 compared to debt issuance costs of $886 million during the year ended December 31, 2022.

These net increases to cash inflows were partially offset by:

•

an increase in principal payments on debt of $875 million due to $5.9 billion of repayments during the year ended December 31, 2023 comprised of:

•

the prepayment of $3.3 billion of the VGLNG Corporate 2025 Term Loan;

•

the repayments of $1.1 billion of the Calcasieu Pass Credit Facilities;

•

the prepayments of $938 million of the Plaquemines Equity Bridge Facility; and

•

the prepayment of $549 million of the VG Commodities Term Loan.

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These compare to $5.0 billion of principal payments on debt during the year ended December 31, 2022, comprised of:

•

the repayment of $3.4 billion for debt associated with the Plaquemines Project;

•

the repayment of $863 million for the 2024 Convertible Notes and corresponding embedded derivative liability;

•

the repayment of $385 million due to the refinancing of the VGLNG Corporate 2025 Term Loan;

•

the repayment of $95 million of the Calcasieu Pass Working Capital Facility; and

•

an increase in purchases of non-controlling interests of $147 million during the year ended December 31, 2023 as compared to the same period in 2022.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

The following table shows a summary of our cash flows for the periods indicated:


	Years Ended December 31,						Change
	2022			2021			($)			(%)
	($ in millions)
Net cash from (used by) operating activities	$	3,702		$	(503	)	$	4,205			NM
Net cash used by investing activities		(2,900	)		(2,078	)		(822	)		40	%
Net cash from financing activities		235			3,623			(3,388	)		(94	)%

Operating Activities

Net cash from operating activities was $3.7 billion during the year ended December 31, 2022, compared to net cash used by operating activities of $503 million during the year ended December 31, 2021. The increase of $4.2 billion was primarily related to

•

an increase of $6.4 billion of cash received for the sale of LNG produced by the Calcasieu Pass Project assets that were placed in service from an accounting perspective between April and August 2022; and

•

a reduction of $226 million of cash paid to settle interest rate swaps that are not designated as cash flow hedges during the year ended December 31, 2022, compared to the year ended December 31, 2021.

These increases to operating cash inflows were partially offset by:

•

an increase of $1.8 billion of cash paid for costs of sales, largely for the purchase of natural gas, at the Calcasieu Pass Project since assets were placed in service from an accounting perspective in 2022;

•

an increase of $342 million of cash paid for operating, development and general and administrative expenses primarily due to increased early construction-related activity at the Plaquemines Project in 2022, prior to the project being deemed probable, and increased operational activity at the Calcasieu Pass Project in support of LNG production during the year ended December 31, 2022, compared to lower pre-production operational support, a portion of which was capitalized, during the year ended December 31, 2021; and

•

an increase of $265 million of cash paid for non-capitalized interest and commitment fees primarily comprised of $105 million at the Calcasieu Pass Project, $104 million at the Plaquemines Project and $56 million at Corporate and other.

Investing Activities

Our investing activities consist primarily of capital expenditures and the purchase, sale and maturity of restricted and unrestricted investments.

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Net cash used by investing activities during the year ended December 31, 2022 and 2021 was $2.9 billion and $2.1 billion, respectively. The increase in cash outflows of $822 million, or 40%, was primarily due to

•

an increase in cash used for purchases of property, plant and equipment of $2.6 billion related to

•

an increase in cash paid for construction of the Plaquemines Project of $2.9 billion for costs incurred after the project was deemed probable in March of 2022, partially offset by

•

a decrease at the Calcasieu Pass Project of $304 million and an increase in cash paid for deposits for construction equipment of $26 million.

These increases in net cash used by investing activities were partially offset by cash proceeds of $1.8 billion from test LNG sales, which was offset against construction in progress during the year ended December 31, 2022.

Financing Activities

Net cash from financing activities during the year ended December 31, 2022 and 2021 was $235 million and $3.6 billion, respectively. The net decrease in cash inflows of $3.4 billion, or 94%, was primarily due to:

•

an increase in debt repayments during the year ended December 31, 2022 of $1.8 billion primarily due to:

•

the repayment of $3.4 billion at Plaquemines for the PL Holdings Credit Facility, the PL Funding Backstop Facility and the Plaquemines Bridge Loan Facility;

•

the repayment of $863 million for the 2024 Convertible Notes and its corresponding embedded derivative liability;

•

the repayment of $735 million due to the refinancing of the VGLNG Corporate 2024 Term Loan and the VGLNG Corporate 2025 Term Loan; and

•

the repayment of $95 million under the Calcasieu Pass Working Capital Facility in year ended December 31, 2022.

These compare to:

•

the debt prepayments of $3.2 billion related to the Calcasieu Pass Credit Facilities and $100 million of the VGLNG Corporate 2024 Term Loan during the year ended December 31, 2021;

•

purchases of non-controlling interests of $1.4 billion during the year ended December 31, 2022, compared to $185 million during the year ended December 31, 2021;

•

a decrease in proceeds from project credit facilities of $680 million due to a $1.7 billion decrease in proceeds under the Calcasieu Pass Credit Facilities, which was fully drawn as of May 2022, partially offset by a $1.1 billion increase in proceeds drawn under the Plaquemines Credit Facilities, which was issued in 2022; and

•

an increase in payments for debt issuance costs of $753 million during the year ended December 31, 2022, primarily related to issuance costs for Phase 1 of the Plaquemines Project, fees incurred for the prepayment of the 2024 Convertible Notes, and issuance costs incurred to increase the VGLNG Corporate 2025 Term Loan, partially offset by prior year debt issuance costs associated with the VGCP Senior Secured Notes.

These increases in cash outflows were partially offset by:

•

an increase in proceeds from the issuance of debt during the year ended December 31, 2022 of $578 million due to $6.0 billion of proceeds from debt issuances in 2022 comprised of:

•

the proceeds of $3.5 billion due to the refinancing of the VGLNG Corporate 2024 Term Loan and VGLNG Corporate 2025 Term Loan;

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•

the proceeds of $2.4 billion due to the $1.9 billion issuance and draw on the PL Holdings Credit Facility, the $400 million increase of the Plaquemines Bridge Loan Facility, and the $100 million issuance and draw on the PL Funding Backstop Facility; and

•

the proceeds of $89 million due to the refinancing of the VG Commodities Term Loan during the year ended December 31, 2022.

These compare to $5.4 billion of proceeds from debt issuances in 2021 comprised of:

•

proceeds from the issuance of $3.8 billion of the VGCP Senior Secured Notes,

•

the issuance of the $1.0 billion Plaquemines Bridge Loan Facility,

•

the $380 million upsizing of the VGLNG Corporate 2024 Term Loan, and

•

the issuance of the $266 million VG Commodities Term Loan during the year ended December 31, 2021;

•

a decrease in net cash used in the settlement of derivatives of $273 million due to the partial settlement of the interest rate swaps related to the Calcasieu Project with a financing component during the year ended December 31, 2021, with no similar settlement activity in the current year; and

•

a decrease in cash used for financed purchases of property, plant and equipment of $200 million during the year ended December 31, 2022, compared to the year ended December 31, 2021.

Contractual Obligations

We have contractual obligations to third parties that impact our liquidity and capital resource needs. As of , 2024, our principal contractual obligations expected to give rise to material future cash requirements consisted of the following: . These obligations can fluctuate significantly from period to period and can materially impact our future results and our future working capital requirements.

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of the consolidated financial statements and interim condensed 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 and assumptions 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 include both fixed and variable components including variable consideration for contingent penalties or fees which may be due from the Company and could result in the significant reversal of revenue. Estimates for penalties or fees 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 “Note 4 – Revenue from Contracts with Customers” to our annual financial statements, included elsewhere in this prospectus, for more information.

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Critical Accounting Policies

Revenue Recognition

The majority of our nameplate capacity produced at the Calcasieu Project and the Plaquemines Project after COD will be sold under long-term 20-year 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 facility charge across our SPAs. Delivery under these post-COD SPAs commences upon achieving COD of the respective LNG facilities, which has not yet occurred for any of our projects. LNG produced prior to an LNG facility achieving COD is sold to various customers under master SPAs, either as single cargos 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 individual molecule of LNG is viewed as a separate performance obligation. 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. Sales of LNG commissioning cargos and under our SPAs include variable consideration for contingent penalties or fees which may be due from the Company, and if so, could result in the significant reversal of revenue. Estimates for penalties or fees 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. Payment terms are within 30 days after the LNG is delivered.

Net proceeds from generation and delivery of test LNG 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 from an accounting perspective.

Capitalization of Development and Construction Costs

Generally, the costs incurred to develop our LNG facilities are treated as development expenses until construction 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 LNG 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 liquidated damages, that impact the amount and timing of the recognition of the related costs. We capitalized costs of $ billion and $19.4 billion into property, plant, and equipment, net as of , 2024 and December 31, 2023, respectively, and recognized development expenses of approximately $ million, $490 million, and $311 million during the three months ended , 2024 and the years ended December 31, 2023, and 2022, respectively. For further discussion, see “Note 6 – Property, Plant and Equipment” to our annual financial statements, included elsewhere in this prospectus, for more information.

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Derivative Instruments

We reflect all contracts that meet the definition of a derivative, except those designated and qualifying as normal purchase or normal sale, 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 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 earnings, at which time the deferred gains and losses are reclassified to earnings. Cash flows associated with derivatives hedging capitalized interest and designated as cash flow hedges are classified as investing 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. Cash flows of our derivatives which are not designated as hedging relationships are classified as operating activities in the Consolidated Statements of Cash Flows. 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 “Note 12 – Derivatives” to our annual financial statements, included elsewhere in this prospectus, 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 “Note 14 – Income Taxes” to our annual financial statements, included elsewhere in this prospectus, for more information.

Quantitative and Qualitative Disclosure About Market Risk

Interest Rate Risk

As of December 31, 2023, our exposure to market risk for changes in interest rates related primarily to the Calcasieu Pass Credit Facilities, the Plaquemines Credit Facilities and our investment portfolio. The Calcasieu

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Pass Credit Facilities and the Plaquemines Credit Facilities accrued interest at term SOFR, plus an applicable margin. Therefore, fluctuations in interest rates will impact our consolidated financial statements. A rising interest rate environment will increase the amount of interest paid on these loans. We entered into interest rate hedge arrangements to manage our interest rate exposure under the Calcasieu Pass Credit Facilities, and Plaquemines Credit Facilities. As of December 31, 2023, we had hedges targeting 97% of our variable rate debt for the Calcasieu Project and 80% of our variable rate debt for both phases of the Plaquemines Project. A hypothetical 100 basis point increase in interest rates would have increased our interest expense by $12.2 million.

The fair value of our credit facilities will generally fluctuate with movements of interest rates, increasing in periods of declining rates of interest and declining in periods of increasing rates of interest. A hypothetical 100 basis point increase or decrease in interest rates would not have had a material impact on the fair value of our credit facilities as of December 31, 2023, December 31, 2022 and December 31, 2021.

The primary objective of our investment activities is to preserve our capital for the purpose of funding our operations. We do not enter into investments for trading or speculative purposes. We generally invest our cash in investments with short maturities or with frequent interest reset terms. Accordingly, our interest income fluctuates with short-term market conditions. As of December 31, 2023 and December 31, 2022, our investment portfolio consisted of $3.4 billion and $378 million, respectively. Due to the short-term nature of our investment portfolio, our exposure to interest rate risk is minimal.

To the extent we utilize additional debt financing, we may incur fixed or floating rate debt or a combination thereof. We will have exposure to changes in interest rates until such time as the interest rates on any such instruments are determined. We will also have exposure to changes in interest rates with respect to any floating rate debt we incur, unless we enter into interest rate hedges with respect to any such exposure.

Commodity Price Risk

We face commodity price exposure in connection with the construction of our projects, and we expect to also face commodity price exposure during operation of our projects, which we seek to mitigate through certain pricing mechanisms in our SPAs.

In connection with the construction of our projects, our exposure to commodity price risk relates primarily to the price at which we are able to execute a reimbursable EPC contract with target price that considers anticipated inflation and models financed contingency to absorb commodity pricing pressure, labor cost increases, and cost overruns for the construction of the relevant project. We expect that price will fluctuate with changes in prices of the relevant commodities to be utilized in the construction of the relevant project, which will primarily be steel, aluminum, nickel, concrete and diesel fuel. In addition, we may be exposed to commodity price risk even after we execute the EPC contract and other key owner furnished equipment contracts for the relevant project, up until the point in time that commodity pricing is locked in and / or procured. For example, for our future projects we may be exposed to changes in prices of such commodities if the relevant project is delayed in issuing notice to proceed (or the equivalent) and that delay results in adjustments to the contract price, or if the scope of the project changes subsequent to execution of the contract. We anticipate that the commissioning cargo proceeds expected to be generated by each project will provide additional contingency that is held at the project-level until certain production milestones are achieved and contingency utilization is replenished.

Following the commencement of operations at our projects, our exposure to market risk for changes in commodity prices will relate primarily to the margin we charge our export customers for feed gas under SPAs. Export customers under our existing SPAs will pay a fee equal to 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. We anticipate that any additional LNG contracts we enter into in the future will

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similarly require our export customers to pay a fixed facility charge per MMBtu, plus a variable commodity charge per MMBtu, in an amount equal to or higher than 115% of the Henry Hub gas price. As a result, changes in the price of feed gas will impact our operating margins. In addition, there may be differences between the actual price we pay for feed gas and the Henry Hub gas price used to calculate the variable commodity charges under the relevant LNG sales contract. Our operating margins would be affected by any such differences.

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LNG INDUSTRY OVERVIEW

Introduction to Natural Gas and LNG

Natural gas is an abundant, cost-effective, and reliable energy source with lower emissions than traditional oil and coal that we believe will play a critical role in supporting the growing global economy for decades to come. Natural gas provides several key advantages over other baseload energy sources:

(i)

Abundant: At year-end 2023, there was an estimated trillion cubic feet, or Tcf, of proven natural gas reserves globally, of which approximately Tcf are located in the U.S., making it one of the largest resources in the world. This abundance ensures long-term availability, encouraging investments in the infrastructure required to extract, transport, and use natural gas

(ii)

Cost Effective: Recent advancements in extraction technologies have significantly boosted natural gas extraction productivity and lowered costs. On average the levelized cost of electricity from gas is , significantly cheaper than coal at and nuclear at

(iii)

Lower Emissions: When used in power generation, natural gas produces 30-60% less CO₂ than traditional oil and coal. Natural gas combustion also releases minimal sulfur dioxide and particulate matter, issuing far less air pollution than other fossil fuels

(iv)

Reliable: Unlike intermittent renewable sources like wind and solar, natural gas-powered generation offers a reliable and steady energy output that can quickly ramp up and cycle to meet rising electricity demand during peak periods or emergencies, as well as balance and contribute to the baseload voltage stability of the power grid

As the global economy continues to grow and the need for reliable, stable electricity generation increases – whether it be from data center demand in highly-developed countries or industrial growth and urbanization in developing regions – the availability, safety, and reliability of natural gas makes it a critical energy source and a key driver towards a cleaner, more sustainable future.

While natural gas is abundant and widely used as a fuel source, global access is challenged by logistic and geographic limitations. Natural gas in its gaseous state can only be transported at scale by pipelines or trucks, and reserves are geographically concentrated in North America, the Middle East, Australia and Russia. Regions without indigenous natural gas supply and limited pipeline connectivity to supply sources, such as Europe and Asia face significant challenges accessing the fuel. Beginning in the 1970’s, the LNG industry has grown dramatically as an efficient and affordable means to supply natural gas to those regions otherwise lacking access to natural gas.

The process of liquefaction facilitates the compression, transportation, and storage of natural gas. Through this proven process, natural gas is cooled down to Fahrenheit ( Celsius) transforming it into a liquid state. Liquified natural gas, occupies just of the original volume, making it easier and cheaper to store and transport large quantities over long distances onboard LNG carriers. The capacity of LNG carriers varies, with modern vessels typically able to transport between to cubic meters of LNG per cargo. Each cargo represents enough energy to power up to homes for one year. Once the LNG reaches its destination, it undergoes regasification, a process where the LNG is warmed back to its gaseous state. The gas is then fed into pipelines or trucks for distribution to meet local industrial and residential energy demand.

Natural gas is a versatile energy source and is widely used across industrial, commercial, and residential sectors. Its primary applications include electricity generation, heating, serving as feedstock to produce various chemical compounds (plastics, resins, fertilizers, etc.), and fuel for heavy duty vehicles and ships. Natural gas consumption is expected to rise in the coming decades, propelled by a shift away from coal and other carbon intensive fuels, the growing trend toward electrification, and global population and economic growth.

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LNG Market

LNG is not traded or sold based on a uniform international price or index. Prices vary significantly across regions due to several factors, including local and global supply-demand dynamics, seasonality, production costs, shipping and transportation costs and geopolitical influences. The profit margin for U.S. LNG producers on exports is typically determined by the difference between the prevailing LNG reference price and the associated local natural gas and liquefaction costs. These reference prices may be set by the spot market or secured through both short- and long-term contractual agreements.

LNG Pricing Composition

The formation of LNG prices is shaped by multiple factors, including:

(i)

Contract Type: This encompasses long-term contracts (typically ranging from four to twenty years), short-term contracts (four years or less), and spot market contracts (for delivery within three months of the transaction date)

(ii)

Benchmark Reference Price: Such as the price of crude oil or natural gas

(iii)

Price Indexation or Escalation Clauses: These may include indexation to inflation or fixed price escalation

(iv)

Commercial Structure: For example, merchant arrangement or tolling arrangement

(v)

Shipping Arrangement: Such as Delivery Ex-Ship (DES), also known as Delivered at Place Unloaded (DPU), or Free-On-Board (FOB)

The specific terms of supply negotiated by the parties involved can materially alter both the contract price formation and the agreed-upon pricing levels.

In a DES arrangement, the seller assumes the full cost and risk involved in transporting goods to a buyer. In an FOB arrangement, the buyer is responsible for transporting the product and assumes all risk once the seller delivers the product.

Benchmark Reference Price

Historical long-term LNG contracts were predominately indexed to the price of certain alternative fuels such as crude oil. Oil-linked LNG pricing remains widespread outside of the U.S., particularly in the Middle East and Asia, representing % of global LNG trade pricing in . Under this pricing construct, LNG is priced as a “percent of” or “slope to” oil. These contracts have been typically priced at around % to % of Brent. However, as U.S. LNG has become more prominent, oil-linked LNG pricing has become less dominant.

Before the rise of U.S. LNG, most LNG-exporting countries lacked a liquid and transparent natural gas market to use as a pricing benchmark, leading to the reliance on oil prices. U.S. LNG introduced a shift in this dynamic due to the existence of an established natural gas trading hub, Henry Hub, or HH. This shift introduces several key benefits:

(i)

Market Reflectivity: HH pricing closely mirrors U.S. natural gas market fundamentals, providing a more accurate reflection of supply and demand conditions

(ii)

Price Stability: Gas-linked pricing tends to exhibit less volatility compared to oil-linked pricing, offering greater price stability for both buyers and sellers, which enhances long-term contract predictability

(iii)

Transparency: As U.S. natural gas and LNG have gained prominence in international energy markets, HH prices have become more widely reported, enhancing market transparency and enabling more informed decision-making

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International Liquid Traded Markets

Aside from HH, the global LNG market is underpinned by several key pricing benchmarks that reflect regional supply and demand dynamics. Among the most prominent are the European Title Transfer Facility, or TTF, the Japan-Korea Marker, or JKM, and the Gulf Coast Marker, or GCM, which reflect the regional natural gas spot price. For volumes shipped to Europe, the price used is typically TTF, and for volumes destined for Asia, the referenced price is typically JKM.

(i)

TTF: The virtual trading point for natural gas in the Netherlands. TTF reflects the price of gas for immediate delivery (spot) and is widely used as a benchmark for natural gas trading and contracts across Europe. The TTF price is crucial for assessing market conditions and is indicative of gas supply and demand in the European market

(ii)

JKM: The virtual trading point for natural gas in Japan and South Korea. Asian markets, particularly Japan and South Korea, have traditionally paid high prices for LNG due to the higher cost of alternative energy sources and strong demand for clean energy in these regions. JKM is widely used by traders, producers, and consumers to gauge LNG pricing and trends in the Asia-Pacific region

(iii)

GCM: A benchmark closely linked to U.S. LNG export activity. GCM reflects LNG bids, offers and transactions on an FOB U.S. basis, normalized to the U.S. Gulf Coast. These prices are quoted on a USD/MMBtu basis. Historical GCM pricing trends have closely followed those of TTF and JKM, just at a lower absolute dollar value. Although cited less frequently than TTF or JKM, the GCM pricing index has become more popular over time as the Gulf Coast LNG sector has developed

Spot Market

Significant growth in the LNG spot market over the past decade has transformed the global LNG landscape. Unlike long-term contracts which span 4 to 25 years and involve fixed pricing mechanisms, the spot market involves the purchase and sale of LNG cargos for near-term delivery, usually within a few months. Producers can sell into these higher-priced and shorter duration markets, with the lowest-cost producers realizing higher margins. This market has introduced greater flexibility, liquidity, and price transparency to the LNG industry.

Cargos sold into the spot market follow different pricing mechanisms relative to traditional tolling or long-term agreements and fluctuate based on current supply and demand. LNG is typically sold in the spot market at international pricing, with the profit that the LNG supplier realizes being the “net spread” (measured in $/MMBtu). Net spreads are determined by subtracting all fixed and variable costs associated with producing (or purchasing) and delivering LNG to the destination market—including pipeline transportation, liquefaction, marine transport and regasification—from the net revenues generated from sales in that market.

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Chart 1: Illustrative Representation of LNG Net Spread ($/MMBtu)

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Unexpected supply constraints to the natural gas supply market can also create opportunities for LNG producers, particularly those with excess, non-contracted supply to fill market needs. For example, in 2023 % of European LNG was purchased in the spot market to fill in the short-term gaps left by the sudden loss of Russian natural gas pipeline flow. Latin America also purchased most of its LNG in the spot market ( %) in preparation for the winter and subsequent heating needs. LNG short-term contract and spot market sales grew rapidly as supply came online, from % of total global LNG trade in 2010 to % in 2023, but such sales still remain less prevalent than longer-term contracts.

U.S. LNG long-term contract pricing

Most LNG contracts in the U.S. today are priced relative to the price for gas at Henry Hub, which serves as the reference for natural gas future contracts traded on the New York Mercantile Exchange, or NYMEX.

The cost structure of long-term U.S. LNG supply agreements typically has three primary components:

(i)

Feed Gas Costs: With many U.S. LNG producers utilizing tolling models and forgoing ownership of the natural gas itself, feed gas costs reflect the cost of buying the natural gas that will then be liquified at the LNG facility. Other producers are responsible for purchasing and transporting gas to their facilities. In both approaches in the U.S., feed gas costs are indexed to HH, typically on a 1-for-1 basis. This cost is simply a pass-through for LNG producers; the offtaker bears the risk of fluctuations in HH prices

(ii)

Variable Costs: LNG producers typically charge offtakers a premium, usually around % of HH pricing, to cover any variable costs at liquefaction projects, including feed gas, power, and transportation costs

(iii)

Fixed Fee: Fixed fees are designed to cover the LNG producer’s fixed maintenance and operating expenses, return on equity, and debt service. A small portion of the fee, between % to %, usually escalates with inflation. Fixed fees have historically fluctuated between $ - $ /MMBtu for long-term contracts, though inflation has pushed these prices higher for new build projects. From

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September 1, 2022 to September 1, 2024, interest rates rose approximately 240 basis points. As a result of these increasing interest rates, rising labor and materials costs, and continued supply chain challenges in the construction industry, fixed fees are expected to approach $ /MMBtu. This is the price needed to fully amortize the project financing at required debt service coverage levels and still provide a return on equity to developers and operators

Long-Term Contracts

Long-term LNG SPAs have traditionally been the most common types of LNG supply agreements. Globally in 2023, % of LNG was traded under long-term contracts, % under short-term, and % in the spot market.

Chart 2: Global SPA Duration signed between January 1, 2023, and February 29, 2024

Long-term SPAs have historically played a central role in the LNG industry for four main reasons:

(i)

Value Chain: The exploration and production of reserves is capital intensive and making such commitments requires a clear path to monetization of the resource. Long-term SPAs granted this clarity to upstream producers and enabled broader investment

(ii)

Financial Security: Long-term “take-or-pay” contracts provide certainty and the financial security necessary for capital-intensive development of LNG projects themselves, including liquefaction plants and associated infrastructure. Project Finance lenders require new build facilities to have executed enough contracts such that the fixed fees payable to the LNG project are sufficient to fully amortize the loans over the duration of the agreements. The creditworthiness of offtakers also plays an important role in LNG project financing. Counterparty risk is largely mitigated as most offtakers are either large investment grade corporations or government-backed entities

(iii)

Reliability of Supply: Buyers, typically utilities and large industrial users, seek long-term contracts to ensure a stable and reliable supply of LNG, crucial for their long-term energy planning. Long-term contracting grew across the world following the European energy crisis which put a premium on long-term supply certainty. In 2023 alone, interregional trade was dominated by long-term contracts with % of global SPAs executed with a duration of more than 10 years

(iv)

Reduce Market Volatility: Long-term agreements help stabilize the market by locking in prices and volumes, reducing exposure to market volatility. These agreements also provide further transparency into future supply as producers must contact potential buyers well in advance of a project’s commercial operations. This transparency provides necessary information for buyers and sellers alike to better forecast their long-term business models

LNG Demand & Supply

LNG Demand

Total global natural gas demand is expected to increase from approximately Tcf in 2022 to approximately Tcf by 2040. LNG today represents % of global natural gas demand (approximately Tcf) and is expected to increase to % of global demand by 2040.

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Chart 3: Global LNG Demand Under Various Scenarios through 2040 (Tcf)

Asian countries such as China and India are rapidly increasing their LNG imports to both meet growing energy needs and to reduce emissions, improve air quality, and comply with stricter environmental regulations. Countries in Europe are similarly looking to diversify their energy sources and reduce dependency on pipeline imports, particularly from Russia. Given their lack of sufficient domestic gas production, these regions will continue to rely heavily on imports from major LNG exporters such as the U.S., Qatar, and Australia over the long-term.

Key Trends Driving Demand

(i)

Coal-to-Gas Switching and Decarbonization

Today, more coal is burned on a daily basis than at any point in history. However, decarbonization efforts are driving a shift from coal to natural gas in power consumption due to natural gas’ lower carbon footprint and greater efficiency. As countries and organizations continue to reduce greenhouse gas, or GHG, emissions, natural gas is increasingly favored over coal as it produces approximately 30-60% less carbon dioxide when combusted for power generation. The United States in particular has already benefited from this transition, with total electric power sector CO2 emissions falling by approximately 30% from 2000 to 2022 largely attributable to coal-to-gas switching. Over the same period, the amount of electricity generated annually by coal in the U.S. declined by approximately KWh. This production was primarily replaced by natural gas-powered electricity, which rose by KWh over the period. As more countries around the world seek to reduce their GHG emissions, we expect the pace of coal-to-gas switching to accelerate, underpinning sustained demand for natural gas and thus LNG.

Chart 4: U.S. CO₂ Emissions Reduction

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Source: EIA’s U.S. Energy Related Carbon Dioxide Emissions, 2019 report

(ii)

Renewables Buildout and Grid Reliability

Natural gas is a vital complement to intermittent renewable energy sources due to its ability to provide reliable and on-demand power. Natural gas plants serve as dependable power sources when renewables generation is unavailable due to decreased wind or sunlight. Gas-fired power plants, which accounted for % of global natural gas consumption in 2023, can quickly adjust output to match demand, providing flexibility and stability to power grids across the world. This flexibility ensures a stable and continuous energy supply, reducing the risk of power outages and grid instability as the share of renewables in the global fuel mix increases.

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(iii)

Global Economic and Population Growth

Population growth and the expansion of the world’s middle class further underpin rising global demand for natural gas. By 2050, the global population is expected to rise to billion from billion today. Concurrently, global disposable net income per capita is expected to increase from $ in 2022 to nearly $ in 2050, or approximately % per year. Certain parts of the world including China, India, and other parts of Asia are forecasted to grow at even faster rates of %, %, and % respectively. With this growth and the continued improvement in global living standards, demand for electricity, heating, and consumer staples are expected to rise rapidly. For example, in developing Asian economies, average per capita energy consumption is expected to increase from KWh in 2022 to KWh in 2030. Despite the global commitment to build out renewables and other low carbon alternatives, this growth and continued improvement will depend on natural gas to affordably stabilize electric grids and support electrification around the world.

Chart 5: Global Population (Bn), Per Capita Disposable Net Income ($000s), and Median Global Electricity Demand Per Capital (KWh)

(iv)

AI Driven Data Center Demand Growth

The surge in demand for artificial intelligence, or AI, data centers is a global phenomenon driven by widespread adoption of artificial intelligence across industries, the expansion of cloud computing, and advancements in technology requiring substantial computational power. Due to increased privacy laws and data security concerns, we anticipate that each developed nation will increasingly elect to develop their own data center and AI infrastructure. Existing estimates put global data center capex above $ per year by with continued acceleration thereafter. This growth is leading to increased energy consumption as data centers house the servers and infrastructure for AI operations and require significant amounts of electricity for both operation and cooling. Global data center driven power demand is expected to increase % by and ultimately account for % of global power demand, relative to only % in . Power generated from natural gas steam turbines offers the most cost effective and carbon efficient option for developers as data center infrastructure continues to proliferate.

Key LNG Markets

Chart 6: Global LNG Demand by Region through 2040 (mtpa)

(i)

Developed Regions

Natural gas demand growth in developed economies is driven by multiple factors that reflect both the evolving needs of the complex energy landscape and realities of the modern world.

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Chart 7: Developed Regions Global LNG Demand (mtpa)

Chinese demand for natural gas has substantially increased as the country has sought to combat air pollution by replacing the use of low-grade coal with electricity powered by natural gas. This demand, supported by government policies, is intended to offset the GW of coal capacity added in 2023. LNG import growth of long-term contracted volumes (not inclusive of spot purchases) is set to increase from million tons per annum (“mtpa”) in to over mtpa in .

In Europe, the Russia-Ukraine War has significantly influenced energy policy and has become a driver of LNG demand as nation-states focus on their energy security. Europe has invested heavily in additional regasification capacity; European LNG regasification projects are set to increase the continent’s LNG import capacity by mtpa before the end of the decade. This additional capacity is expected to significantly boost LNG demand, which is forecasted to grow by mtpa over the next decade.

(ii)

Developing Regions

Demand for LNG in developing markets is expected to be fueled by rapid demographic and economic growth. As populations grow, they inherently demand more energy for residential, commercial, and industrial uses. The expanding middle class is driving an increased demand for a higher standard of living, including greater access to energy-intensive goods; when incomes double, consumers are found to be % more likely to own a refrigerator and % more likely to own a computer. For example, in developing parts of Asia, average per capita energy consumption is expected to rise from KWh in 2023 to KWh in 2030. Natural gas is expected to be key to meeting the projected increase in demand by offering affordable, clean, and reliable baseload power.

Chart 8: Developing Regions Global LNG Demand (mtpa)

Developing regions are expected to experience robust LNG demand growth with Southeast and South Asia a part of the fastest-growing LNG markets. Their increase in demand is spurred by a % expected increase in population (equivalent to million people by 2050). This growth is further compounded by increasing urbanization and levels of disposable income increasing at a rate of as fast as % per year in certain countries. With domestic gas production in terminal decline for many nations in the region, LNG imports are expected to materially ramp up through and beyond the 2040s to support these macroeconomic trends.

LNG demand in other developing regions outside of Asia is also projected to steadily grow. In both Africa and South America, natural gas demand growth is expected to outpace domestic supply growth, increasing reliance on imported LNG. African demand is expected to be driven by “strong economic expansion, continued industrialization and rapidly rising urban population, accompanied by an accelerated increase in electricity needs.” With these macroeconomic changes, African LNG imports are expected to quadruple by 2030. Meanwhile in South America, key demand growth drivers include fuel switching, industrial development, baseload power to backup intermittent renewables, and road transportation. The region is consequently projected to see LNG imports rise from mtpa in 2022 to mtpa in 2050.

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LNG Supply

Current global LNG production capacity stands at approximately mtpa, with the majority concentrated in regions such as the U.S. ( % share of total capacity), Australia ( %) and Qatar ( %). In 2023, these three countries produced % of the world’s LNG supply.

Chart 9: Global LNG Supply Forecast by Region (mtpa)

Global LNG supply from projects in operation and under construction is projected to reach mtpa by 2030. This represents a % increase from 2023 levels. Approximately mtpa of LNG capacity is currently under construction, with % coming from expansion projects. Projects under construction represent over of expected supply by 2030. The expected new supply will primarily come from the U.S., Qatar, and floating LNG projects in Africa. The U.S. is at the forefront with five major projects under construction comprising over of total projected additions.

Many projects aspire to reach FID in the coming years, but not all will succeed. Developing LNG projects is a complex and challenging process that requires careful planning, significant resources, and expertise. Additionally, LNG projects often face delays due to external factors such as labor costs and supply chain disruptions, financing challenges and regulatory hurdles. For example, an all-time high of more than mtpa of capacity reached FID in 2019 but many had their production start dates delayed. Qatar saw the timeline of its mtpa North Field Expansion project delayed due to supply disruptions. Golden Pass, an mtpa project in the U.S. by Qatar Energy and ExxonMobil, is behind schedule due to construction issues. Mozambique LNG, a mtpa project led by TotalEnergies, has been halted since 2021 and it still under force majeure due to security concerns arising from violent insurgent attacks in the region. If this level of capacity approved in 2019 were not impeded, the market would see an additional mtpa of supply per year from 2025 to 2027. These challenges are not new or novel in the LNG industry. For instance, LNG Canada, a Shell sponsored project, which was first announced in 2012, did not take FID until 2018, and has been delayed multiple years so far with first LNG currently targeted for mid-2025. Should under-construction projects get further delayed in the range of 6-12 months, it would remove million tons of supply in 2025 and million tons in 2026.

Declining production curves from historic export centers of oil and gas also weigh on future projections of LNG supply. In Southeast and South Asia, total production from operating facilities in Indonesia, Malaysia, and Brunei is expected to decline from mtpa in 2023 to mpta in 2030. Similarly, legacy assets in Africa are projected to decline from a peak of mpta in 2021 to mtpa in 2030. Further, Trinidad and Tobago, which boasts a 15 mtpa facility, has seen reduced flows from its gas fields leading to the idling of trains. By 2030, its natural gas supply is projected to decline by %. These declines in natural gas supply further underpin the need for LNG project development in the near term, particularly in regions like the U.S. that house multiple, discontinuous natural gas basins. LNG projects fed by a single basin are necessarily constrained by the supply of a single location. Conversely, projects in the U.S. enjoy diversified sources of supply accessible by robust, layered transportation infrastructure.

United States

The U.S. exported over million tons of LNG in 2023, claiming the lead spot among global LNG exporters. There are seven operating LNG facilities in the continental U.S. with a combined capacity of mtpa of LNG. These facilities represent one fifth of the world’s total LNG production capacity. Current U.S. LNG projects under construction are expected to add as much as mtpa of export capacity by 2030, barring delays.

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LNG supply in the U.S. is bolstered by strong, enduring supply and technology trends, driving its swift ascent to the top as the world’s leading LNG exporter. To start, the U.S. has the largest share of natural gas production among all regions globally, accounting for % of total natural gas production. U.S. gas production continues to steadily rise, recently growing % from 2022-2023. This growth is primarily driven by the increase in production from prolific gas regions in the Permian Basin and Haynesville Shale. At year-end 2023 U.S. proved natural gas reserves were estimated at Tcf, reflecting the nation’s significant resource potential. Advancements in extraction technologies such as hydraulic fracturing and horizontal drilling continue to enhance production efficiency and reduce costs. A robust, well-established network of transportation pipelines facilitates distribution of natural gas from the wellhead to end demand.

Chart 10: U.S. LNG Supply Forecast (mtpa)

Middle East

The Middle East is a critical player in the global LNG market, with Qatar, Oman, and the United Arab Emirates, or UAE, leading the region’s export capabilities. Qatar is the dominant supplier with a current production capacity of mtpa. This capacity is primarily sourced from the vast North Field, the largest non-associated natural gas field in the world. The total estimated recoverable reserves of the North Field are approximately Tcf of natural gas. Oman and the UAE’s export capabilities are more modest in comparison. Oman holds mtpa of LNG capacity across its facilities in Qalhat and Sur. UAE operates a mtpa facility on Das Island.

The Middle East’s LNG production is sustained by its vast and easily accessible natural gas reserves. The region’s growing infrastructure, including pipelines and export facilities, strengthens production and distribution. Access to capital allows significant investment in exploration and technological advancement. Further, the Middle East’s proximity to major energy markets in Europe and Asia reduces transportation costs.

Qatar, Oman, and the UAE are actively planning to develop additional LNG projects to further expand their export capabilities. Qatar plans to increase liquefaction capacity to mtpa by 2030 through its North Field expansion projects. However, this proposed expansion is not without risk: delays in the bidding process have already extended its timeline. Additionally, the UAE’s state-run Adnoc approved the mtpa Ruwais project in June 2024, which is expected to begin production in 2028. TotalEnergies is also moving ahead with the mtpa Marsa LNG bunkering project in Oman, slated for 2028 commencement. This project will primarily supply marine fuel for the Gulf region.

Chart 11: Middle East LNG Supply Forecast (mtpa)

Middle Eastern gas production entails several unique risks. LNG producing countries in the region are dependent on large, single-source fields, which make supply vulnerable to disruptions. The concentration of liquefaction sites in a few strategic locations also poses logistical and security challenges. Heightened geopolitical risks including regional conflicts and political instability may threaten production and export continuity. For example, ongoing regional wars are disrupting key shipping channels in the Strait of Hormuz and the Suez Canal. Such disruptions have plagued regional supply chains for decades and are not limited to the present conflicts.

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Australia

Australia is one of the world’s largest LNG producers. In 2023, Australia exported million tons of LNG. Australia’s rise as a world leader in LNG production has been driven by several key factors. The country has sizable natural gas reserves in Western Australia and Queensland. Moreover, its strategic geographic location close to major Asian markets allows for efficient export routes and low shipping costs. Lastly, Australia’s regulatory environment helped attract investment to the LNG sector. Australia’s LNG supply is expected to remain stable throughout the decade, averaging around mtpa, although escalating construction costs and a tightening domestic gas market could constrain exports in the future. For example, in 2024, the Northern Territory government had to execute emergency gas deals that limited LNG exports due to declining production at the Blacktip field. Australia’s East Coast is forecast to experience gas shortfalls starting in 2028.

Chart 12: Australia LNG Supply Forecast (mtpa)

Russia

Russia is a significant player in the global LNG market. In 2023, Russia exported million tons of LNG. Russia’s LNG production is supported by its abundant natural gas reserves, particularly in the Yamal Peninsula and Artic regions. Further, its production capacity is strategically enhanced by its proximity to European and Asian markets. The Northern Sea Route in particular facilitates shorter shipping times to Asia. Key LNG facilities include the Sakhalin-2 project, Yamal LNG, Petrovaya LNG and Vystosk LNG. Still, in 2023 Russia continued to supply mtpa of natural gas to Europe.

Russia’s plan to triple LNG output by 2030 has been derailed by the extensive rounds of sanctions following its invasion of Ukraine in 2022. These sanctions are not only stalling projects under-construction but also posing a risk to current operational facilities. Sanctions imposed on Russia by Western nations in response to the invasion of Ukraine in 2022 have had significant repercussions on the country’s LNG production and export capabilities, making future supply of Russian gas uncertain.

Chart 13: Russia LNG Supply Forecast (mtpa)

Supply and Demand Imbalance

Given the factors discussed above, an undersupply of LNG by of mtpa is being projected. This shortfall is expected to widen to mtpa by .

Chart 14: Combined LNG Supply and Demand Forecast (mtpa)

Further, it is possible that this shortfall is understated. Historic projections of demand have failed to accurately predict growth in demand, often understating it by an appreciable margin. For example, the

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International Energy Agency, an intergovernmental entity, publishes an annual World Energy Outlook that is utilized by governments to inform policy decisions. The report often includes projections of LNG demand globally. Their projections for 2010, 2015, and 2020 understated realized demand by 21%, 8%, and 29%, respectively, on average across reports dating back twenty years.

Likewise, projections of supply in the LNG market also can be overstated. LNG projects face a litany of challenges to reaching production including siting, regulatory, contracting, financing, construction, and operational headwinds. As can be seen in the chart below, even large multi-national corporations and nation states have struggled to reach first production of LNG in line with initial expectations, often seeing delays of multiple years compared to their initially announced timelines.

Chart 15: LNG Project Timelines

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Taken together, these trends in conservative estimates of demand and overly optimistic projections of supply present the possibility of an even wider supply and demand gap than is currently anticipated by market analysts and participants. Such an imbalance may raise LNG prices from recent levels and provide opportunities for LNG project developers to meet the coming demand.

Rise of U.S. Liquefaction

The United States has emerged as one of the global powerhouses in LNG production by leveraging its vast natural gas reserves, cutting-edge extraction technologies, extensive pipeline infrastructure, and broadly supportive political and regulatory environment. Additionally, its strategic location and the development of LNG terminals along the Gulf Coast provides access to key global markets. While historically the U.S. has been an importer of natural gas, recent technology advancements and investments have transformed the country into a net exporter with the proceeds from exports broadly distributed throughout the U.S. economy. LNG exports have bolstered the U.S. trade balance, particularly with China, and generated substantial local, state and federal tax revenue. Each LNG project requires thousands of construction jobs and hundreds of permanent operation jobs, with cascading effects through the financial and legal services and domestic manufacturing sectors.

The surge in U.S. LNG production not only generates substantial economic benefits—such as job creation, trade deficit reduction, and increased local, state and federal revenues—but also plays a critical role in global energy security. U.S. LNG offers an alternative to more carbon intensive energy sources, while also promoting adherence to stringent environmental and social standards, thereby contributing to the global effort to mitigate the impact of fossil fuels.

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Abundant Natural Gas Resources

Chart 16: U.S. Natural Gas Basins and Pipeline Infrastructure

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Sources:

U.S. Energy Information Administration, “Natural gas explained: Natural gas pipeline” and U.S. Energy Information Administration, “Natural gas explained: Where our gas comes from”

The U.S.’s substantial natural gas reserves position the country as one of the world’s leading producers and exporters of natural gas. The U.S.’s proved natural gas reserves were estimated at approximately Tcf at year-end 2023. These reserves are primarily concentrated in key areas including the Marcellus and Utica Shales (both in Appalachia), Permian Basin (includes Delaware and Midland), Haynesville Shale, and Eagle Ford Shale. These ample reserves offer a robust foundation for meeting domestic energy needs and expanding exports to global LNG markets. Furthermore, production of natural gas in the U.S. has been increasing since 2006 and the rate of increase has accelerated since 2017. In 2023, U.S. natural gas production grew by 4%, or 5.0 billion cubic feet per day (Bcf/d), to 125.0 Bcf/d. In the same year, global gas production only increased by %, driven by the production expansion in the U.S. and European production decline. Natural gas production in the U.S. is expected to keep growing, reaching Bcf/d by .

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Chart 17: U.S. Natural Gas Production (Bcf/d)

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Source:

U.S.	Energy Information Administration, “Short Term Energy Outlook”, August 2024

The Appalachian, Permian, and Haynesville Basins are the richest natural gas basins in the U.S. Each holds various formations with large natural gas reserves.

(i)

The prominent shales in the Appalachian Basin are the Marcellus and Utica shales. The Marcellus Shale, with an estimated Tcf of recoverable gas, is one of the largest natural gas reserves globally. Additionally, the Utica Shale reserves are estimated at around Tcf. In 2023, more natural gas was produced in the Appalachia region than in any other U.S. region. Total production reached 37.7 Bcf/d, which represents 29% of gross natural gas production

(ii)

The Permian Basin is located in western Texas and southeastern New Mexico and is home to multiple resource formations, including the Wolfcamp, Spraberry, and Bone Spring, and holds almost Tcf of natural gas. The Permian region produces the second-most natural gas in the U.S., accounting for 19% of domestic production. Additionally, since early 2023, the Permian region has had more active rigs than all other natural gas deposits in the Lower 48 states combined and has continued to build hundreds of wells annually. Natural gas production growth in the Permian region is largely driven by the increase in associated gas generated during oil extraction. Oil is historically the key focus of the region and consolidation amongst producers has led to an increase in both production and the need for pipeline offtake of associated gas. In 2023, gross natural gas production in the Permian region rose by 2.6 Bcf/d to an average 23.3 Bcf/d. This increase has played a role in expanding the basis differential between Permian volumes and those sold at Henry Hub. As a result, there has been increased development of long-haul pipelines seeking to alleviate the oversupply

(iii)

The Haynesville Shale located in northwest Louisiana and eastern Texas has an estimated recoverable resource base of approximately Tcf of natural gas. In 2023, the Haynesville region accounted for 13%, or 16.8 Bcf/d, of gross natural gas withdrawals, a 1.4 Bcf/d increase from 2022. In 2022, natural gas production in the Haynesville region had grown by 2.1 Bcf/d. Natural gas production growth in the region is fueled by a favorable regulatory environment and its proximity to the Gulf Coast LNG export facilities such as ours

The U.S. was a historical net importer of natural gas importing on average per year from 2010 to 2016. Advancements in efficient extraction technologies, particularly hydraulic fracturing, have significantly lowered

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natural gas prices and led to the U.S. becoming a net exporter of natural gas in 2017 for the first time in approximately 60 years. In 2023, the U.S. became the world’s largest exporter of LNG, surpassing Qatar and Australia with mtpa exports.

Chart 18: U.S. Natural Gas Production vs. Consumption

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Source:

U.S. Energy Information Administration, Monthly Energy Review, Table 1.2, April 2024, preliminary data for 2023

Extensive Pipeline Infrastructure

The U.S. distinguishes itself with its advanced natural gas infrastructure, featuring an extensive pipeline network and highly efficient storage facilities. This robust system enhances energy reliability and ensures low transportation and distribution costs. The existing pipeline infrastructure enables the transport and storage of natural gas from supply locations to coastal areas in the U.S., where it is liquefied and shipped. As a result, while other nations struggle to transport natural gas for export, U.S. LNG producers can offer competitively priced LNG globally.

U.S. natural gas domestic infrastructure includes approximately three million miles (4.8 million kilometers (km)) of pipelines divided into intrastate and interstate systems. This vast network supports the transportation of around 80 Bcf/day of natural gas. This expansive infrastructure enables Venture Global’s facilities to source natural gas from multiple regions across the nation, ensuring we are not dependent on any single natural gas basin or pipeline for natural gas feedstock.

The U.S. is currently investing $11.5 billion to build over 900 miles (approximately 1,500km) of new natural gas pipeline. This pipeline infrastructure expansion is largely focused on expanding existing transmission capacity or increasing export capacity from the Permian Basin and Haynesville Shale. The ambitious and ongoing buildout of pipeline infrastructure is aimed at serving the Gulf Coast LNG export terminals, which is where our liquefaction sites are located. Key projects include the 2.5 Bcf/d Matterhorn express 580-mile pipeline and the Bcf/d -mile Apex pipeline, both designed to improve transport from production hubs to export facilities in the Gulf Coast. This increased pipeline capacity enables natural gas producers to expand production, as natural gas can be efficiently transported from extraction sites to end markets without logistical constraints.

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BUSINESS

Overview

Our Company

Our Projects

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(1)	Targets based on, among other things, anticipated timeframes for the receipt of certain regulatory approvals as described in “—Governmental Regulation.”

(2)	Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval, among other things, and may change based on design considerations, engagement with contractors, and other factors.

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Our Project Development and Construction Approach

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Gas Supply and Transportation

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LNG Sales – Commissioning

LNG Sales – Post-COD SPAs

Excess Capacity

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Optimization and Bolt-on Expansion Opportunities

Potential Additional LNG Projects and Further Integration

In addition to our current projects, we regularly explore opportunities, both domestic and international, to develop or acquire other potential natural gas liquefaction and export projects, as well as other complementary, synergistic or ancillary projects, in the ordinary course of our business. As described below, we have already engaged in substantial activities to establish complementary pipeline projects, LNG tanker and regasification business lines that could be leveraged for other potential natural gas liquefaction and export projects in the future. Our experienced project execution team, who have deep industry expertise in the LNG, shipping, midstream and construction industries, possess the institutional agility and capital to rapidly evaluate and act upon opportunities as they arise and we believe differentiate us from our competitors.

Pipeline Projects

Shipping

Regasification

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Alexandroupolis, or approximately 12 cargos annually. We believe these contracted capacities will allow us to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers. As in the case of our shipping business, many LNG developers have elected to forego integrating regasification into their broader business. Relatedly, many LNG customers lack direct access to regasification capacity. We believe our regasification access will allow us to offer spot and term customers a differentiated service, ultimately positioning us to win market share.

Our Strengths

Our business has a number of competitive strengths, including the following:

•

Industry leading growth in the critical global LNG market. We believe that we are the fastest growing developer of LNG facilities in the competitive global supply market. Since the second half of 2019, Venture Global and its affiliates have reached final investment decision for three large-scale, greenfield liquefaction facilities (consisting of the Calcasieu Project and Phase 1 and Phase 2 of the Plaquemines Project) being developed in the United States. We believe that, during this same period, no other developer achieved such a milestone for more than a single large-scale infrastructure project in the world. We expect to increase our LNG production capacity further as we continue our work to optimize our existing projects and develop the CP2 Project, the CP3 Project, the Delta Project, bolt-on and other expansion opportunities, and other investments.

•

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all individual components have been commissioned, production continues while we complete full commissioning of the integrated facility and conduct any carryover or rectification work. During such process, we complete performance testing of the entire fully-integrated facility and validate reliable operational performance. We expect that each project’s construction plan and sequencing will be designed to allow LNG to be produced, stored and loaded onto ships for export, and sold as commissioning cargos, generating cash proceeds.

•

Stable, long-term cash flows and valuable commissioning cargos and excess cargos.

•

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Project are located at or near the mouth of the Calcasieu Ship Channel, and the Plaquemines Project and the Delta Project are located approximately 300 miles east and are sited next to the Mississippi River, each of which provides ready access to our facilities from the Gulf of Mexico. Since they are located at or near the mouth of the Calcasieu Ship Channel, the Calcasieu Project, the CP2 Project and the CP3 Project sites’ geography also allow for faster entry into and exit from our berthing docks relative to many other facilities in the region. Our current projects are also located in close proximity to major population centers, providing ease of access for workers and transportation of materials. The Calcasieu Project and Plaquemines Project sites also benefit from full road and water access, and buffer lands to facilitate deliveries and serve as laydown areas, and we expect sites of the CP2 Project, the CP3 Project and the Delta Project to benefit from the same access and buffer lands. We believe our current project sites provide significant opportunities for bolt-on expansions that would benefit from pre-existing plant facilities and related infrastructure (such as common pipe racks, marine offloading facilities and perimeter walls). Moreover, we believe Louisiana is a favorable legal, regulatory and political jurisdiction for our projects.

•

Experienced management team aligned with stakeholders.

•

Our competitive strengths are subject to several risks and competitive challenges. Please read “Risk Factors” and “—Competition.”

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Our Business and Growth Strategies

Since our founding in 2013, we have grown rapidly from a two-person company into the formidable energy market disruptor we are today. We now employ over people globally and are commissioning, constructing, and developing five natural gas liquefaction and export projects. We also now own or lease or have an option to own or lease nearly 6,000 acres of strategically located land in Louisiana, much of which benefits from significant deep-water frontage. Although we have a limited operating history and did not generate any proceeds prior to 2022, as of , 2024, we have raised approximately $ billion of capital and generated over $ billion in gross proceeds from sales of commissioning cargos, resulting in over $ billion of net proceeds. We have also executed mtpa of post-COD SPAs, representing % of the volume of SPAs contracted by producers on the US Gulf Coast since and expect total contracted revenue of approximately $ billion over the life of such SPAs. Notwithstanding these accomplishments, we are acutely focused on further growth and plan on pursuing the following three core drivers to expand our scale, profitability and impact on the global energy industry.

•

Bolt-On Expansions

•

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•

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(1)	Targets based on, among other things, anticipated timeframes for the receipt of certain regulatory approvals as described in “—Governmental Regulation.”

(2)	Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors.

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

Vertical Integration and Opportunistic Investment

•

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Our Liquefaction and Export Projects and Key, Complementary Assets

In the subsections that follow, we provide a detailed description of our core business—our liquefaction and export projects—and our key, complementary assets along the energy supply chain.

Our Liquefaction and Export Projects

At a high-level, LNG facilities require (i) an input of natural gas, (ii) pre-treatment plants to remove impurities from the natural gas, such as water, CO₂, mercury, benzene, and other heavy molecules, that would disrupt or damage other equipment required to produce LNG, (iii) liquefaction plants to supercool the gas and convert it into LNG, (iv) LNG storage tanks to collect and store the LNG prior to loading into LNG tankers for export, (v) deep water access, or frontage, with a jetty and marine berth to load LNG onto LNG tankers, (vi) a power plant or access to the electricity grid to provide the significant amount of electricity required to operate the foregoing systems and equipment, and (vii) extensive “balance of plant” facilities, including piping and piperacks to interconnect, protect, and support the foregoing systems and equipment.

The traditional approach to developing large-scale LNG facilities (i.e., 10 mtpa or more) involves very large, highly customized, stick-built projects consisting of two to three liquefaction trains, each with a nameplate capacity of 4-6 mtpa, that are constructed almost entirely onsite by vast workforces. Due to the size of these liquefaction trains, incremental capacity at traditional LNG facilities generally can only be added in lump-sum, step-function expansions that often require significant investment in the corresponding balance of plant as well as additional land. In effect, expansions of such facilities become projects unto themselves and lose their marginal cost advantage over new build facilities. In addition, many of these large, international, stick-built projects are built in remote locations far away from concentrated sources of experienced construction workforces, adding to their lengthy construction and execution timelines.

Our company was established with the goal of pioneering a new, mid-scale, factory-made liquefaction train configuration, paired with our unique owner-led construction and risk management approach to construct LNG facilities, that aims to minimize EPC scope, optimize the construction schedule to produce LNG earlier in construction, lower costs, and increase reliability. Wherever possible, we seek to leverage the benefits of factory-built systems and limit the amount of stick-built or other on-site fabrication. Given our unique project configuration (which includes many mid-scale liquefaction trains), it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-size liquefaction trains. This occurs through a longer commissioning period where our modules and key equipment, and various discrete systems are installed and integrated in parallel with ongoing construction activities. Our modules and key equipment undergo a comprehensive commissioning program, which includes performance testing of individual components and, subsequently, of the entire, fully built facility. Each of our liquefaction and export facilities includes certain key, standardized, modular equipment that follows our “design one, build many approach,” which provides for significant redundancy and interoperability throughout the facility. This key equipment includes our liquefaction trains, gas pre-treatment systems, power island systems (which are self-sufficient power plants that do not rely on electricity from the electricity grid), LNG storage tanks, and marine loading berths. We aim to utilize this repeatable configuration across the projects that we develop to continually refine and optimize our LNG production operations.

Our liquefaction trains, gas pre-treatment systems, and power island systems are primarily manufactured and assembled off-site in factory settings. Our liquefaction trains are manufactured by Baker Hughes and are each designed with a nameplate capacity of 0.626 mtpa. Nameplate capacity measures the minimum guaranteed operating performance thresholds guaranteed by the equipment providers. We also aim to construct and maintain LNG facilities that are capable of producing excess capacity, in most cases, of at least 30% of their guaranteed nameplate capacity. We deploy our liquefaction trains in blocks, consisting of, among other things, two liquefaction trains, a cold box (which is used to lower the temperature of natural gas to the point at which it liquefies), and an electrically driven compressor. Our gas pre-treatment systems utilize processing technology

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from UOP LLC, or UOP, a subsidiary of Honeywell International Inc., or Honeywell International, and are purchased in quantities designed to support production capacities well in excess of our projects’ production capacity. Our power island systems are self-sufficient power plants that do not rely on electricity from the grid and are purchased from Baker Hughes. Depending on the size of the facility, the power island systems consist of one or more nominal 620 MW (720 MW at peak) inside-the-fence, air-cooled combined cycle gas-fired power plant (with five gas turbine generators and two steam turbine generators) and one or more nominal 23 MW LM2500 gas turbines that supports frequent cycling and provide back-up power and black start capabilities. Our power equipment is manufactured off-site by General Electric.

Our LNG storage tanks and marine loading berths are constructed on site by specialized contractors. Our LNG storage tanks are constructed by CB&I at an industry leading pace and are designed to be among the largest LNG tanks in the industry at 200,000 m³. We also design our facilities with multiple marine loading berths that are interoperable with our LNG storage tanks and are capable of loading one or more LNG tankers in parallel.

We design our facilities to incorporate supplemental capacity throughout the facility to safeguard the availability of our mid-scale train configuration with a goal of achieving high levels of redundancy and flexibility, which we believe will increase our availability and production. For example, redundancy is present in our gas pre-treatment systems, as each pre-treatment unit is designed to meet approximately 50% of our production requirements – for every 10 mtpa of nameplate capacity, we have approximately 15 mtpa of pre-treatment capacity. Further, we build enough 200,000 m³LNG storage tanks at each of our projects to service up to 150% of its nameplate capacity. We combine this redundancy with interoperability that allows us to load LNG from any individual liquefaction train into any LNG storage tank for the relevant facility. Each tank in turn can load a cargo via any jetty. Once complete, we believe this equipment and our “design-one, build-many” facility design has the potential to provide greater operational redundancy and availability, reducing planned and unplanned downtime and enabling us more to reliably deliver LNG to our customers, and to increase production from our existing equipment. The benefits of our “design one, build many” approach extend further, as our two existing projects can provide our future projects with a source of interchangeable parts and a venue to train personnel on identical equipment. The ability to pool resources across our projects will increase our operating leverage and may augment our earnings through reduced fixed and variable operating expenses.

Our projects are also designed to benefit from significant potential bolt-on expansion capacity, or expansions to our existing project sites beyond our current targets, that we intend to explore in the future. Subject to receiving the requisite regulatory approvals, we believe our projects offer potential optimization, increased capacity and expansion opportunities. In particular, we believe our current project sites provide attractive opportunities for potential bolt-on expansion (for example, by adding additional liquefaction trains, subject to regulatory approvals) beyond the current combined expected peak production capacity of 143.8 mtpa, potentially at reduced construction costs. We intend to pursue these bolt-on expansion opportunities in the future and believe that we have the potential to add 35.2 mtpa in total across the Calcasieu Project, the Plaquemines Project, the CP2 Project, and the Delta Project as outlined below based on current, actual and anticipated project design, as applicable, and subject to regulatory approval. These expansion opportunities do not contemplate any expansion at the CP3 Project due to its considerable 30 mtpa expected nameplate capacity. We believe any such incremental equipment would benefit from pre-existing plant redundancies (such as in our power island and gas pre-treatment equipment) and related infrastructure (such as marine facilities, LNG storage tanks and perimeter walls), though additional plant components will likely be required and there are constraints on our existing equipment being able to be used towards the bolt-on expansion. We expect that increases to LNG production from either optimizing existing equipment and systems or incremental bolt-on expansion may significantly lower the net cost of liquefying LNG and increase profits as LNG is sold more attractively into the commodity markets.

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Below is a geographic overview of our five current projects, which is followed by a detailed description of each project.

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Calcasieu Project



Calcasieu Project

Project location:

Site		Approximately 432 acres in Cameron Parish, Louisiana

Property rights		Ground leases for 30 years, with options to extend to 70 years

Deep-water frontage		Approximately 1.0 mile

Project design:

Expected nameplate capacity		10.0 mtpa

Expected peak production capacity		Up to 12.4 mtpa

Potential bolt-on expansion incremental capacity		Up to 4.5 mtpa⁽¹⁾

Liquefaction system		18 liquefaction trains

LNG storage		2 × 200,000 cubic meter cryogenic LNG storage tanks

Power supply		1 power island system (with a capacity of 620 MW nominal / 720 MW peak and consisting of 5 gas turbine generators and 2 steam turbine generators along with related equipment)

Gas pre-treatment system		3 units, each designed to support 50% of the expected nameplate capacity (1 redundant unit)

Berths		2 berths, each designed to accommodate vessels of up to 185,000 cubic meters in capacity

Lateral pipeline		Approximately 24-mile long lateral

Key permits:

FERC approval		12.4 mtpa (February 2019 and September 2023)

DOE approval – FTA Nations		12.4 mtpa (September 2013 and April 2022)⁽²⁾

DOE approval – Non-FTA Nations		12.0 mtpa (March 2019)⁽²⁾⁽³⁾

Project timeline:

Final investment decision / financial closing		August 2019

First LNG production		January 2022

Targeted COD

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

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(2)	Cumulative exports to FTA Nations and Non-FTA Nations cannot exceed the permitted capacity as authorized by the FERC.

(3)	Our request to increase the authorized level of exports to Non-FTA Nations from 12.0 mtpa to 12.4 mtpa is still pending. See “—Governmental Regulation—DOE Export Authorizations—Calcasieu Project.”

Project Description

The Calcasieu Project is a liquefaction and export facility in the commissioning phase, with an expected nameplate capacity of 10.0 mtpa and an expected peak production capacity of 12.4 mtpa, located on approximately 432 acres of land in Cameron Parish near the Gulf of Mexico and south of Lake Charles, Louisiana, with approximately one mile of deepwater frontage on the east side of the Calcasieu Ship Channel.

The Calcasieu Project consists of 18 mid-scale, factory-built liquefaction trains (9 integrated single mixed refrigerant blocks) and support facilities. The Calcasieu Project also includes three gas pre-treatment units (each designed to support approximately 50% of the gas pre-treatment needs of the Calcasieu Project), two 200,000 m³full containment LNG storage tanks and two marine loading berths rated at 12,000 m³/hr. The Calcasieu Project is powered by a newly constructed nominal 620 MW (720 MW at peak) inside-the-fence, air-cooled combined cycle gas-fired power plant, which is dedicated solely to providing electricity to the Calcasieu Project and supporting facilities. The power plant is complemented by a nominal 23 MW LM2500 gas turbine that supports frequent cycling and provides back-up power and black start capabilities. An approximately 24-mile long lateral pipeline connects the liquefaction plant to the existing interstate and intrastate natural gas pipeline system to receive feed gas for liquefaction and for the power plant.

Project Site Real Estate

Our existing ground leases with various landowners covering the land on which the Calcasieu Project and our marine offloading facilities for the Calcasieu Project are located allow us to extend the initial lease period of 30 years for up to four additional ten-year terms, up to 70 years in the aggregate. See “—Properties” for more information.

Project Construction and Commissioning

We made our FID for the project in August 2019, loaded our first LNG cargo for sale in March 2022, and all 18 liquefaction trains were capable of producing initial quantities of LNG by July 2022.

The Calcasieu Project was constructed pursuant to several key contracts, including an EPC contract, or the Calcasieu EPC Contract, with Kiewit Louisiana Co., or Kiewit. Under the Calcasieu EPC Contract, Venture Global was responsible for executing or directly managing significant scopes of work. The work performed by Kiewit included contributions to the design, engineering, erection, and integration of the balance of the facility not otherwise provided by Venture Global’s vendors – who delivered the majority of modules and key equipment for the project. Kiewit’s work also included facilitating the passage of performance tests for the liquefaction trains and power plant. See “—EPC Contracts,” for more information.

Venture Global directly contracted with other contractors to design and manufacture the main operating components of the facility. Baker Hughes fabricated the mid-scale, factory-built liquefaction trains and also provided, through a General Electric subsidiary, a comprehensive combined cycle gas-fired power plant for the project. All equipment provided by Baker Hughes was delivered to the site and installed or incorporated in the facility. Weeks Marine, a proven leader in maritime construction, constructed a perimeter wall that is designed to fully enclose (along with the marine-side berm) and protect the project as well as two marine loading berths. CB&I LLC, or CB&I, a subsidiary of McDermott International, Ltd., constructed the two LNG storage tanks. UOP provided the natural gas pre-treatment equipment which was delivered to the site and installed or incorporated in the facility. WHC LLC, or WHC, constructed the TransCameron Pipeline. Baker Hughes, Weeks

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Marine, CB&I and UOP provided Venture Global with guarantees of the performance of the components they provided and assumed obligations to “make good” on certain deficiencies, which generally entails an obligation by such contractors, at their own cost, to ensure performance meets certain guaranteed minimums.

Construction of the Calcasieu Project is substantially complete and the project is currently undergoing a multi-faceted commissioning program to complete the facility’s components, bring them to design specification and establish reliable and safe facility-wide operating conditions and to prepare for the commencement of lender-required performance reliability testing. Significant work related to commissioning, carryover completions, and rectification is ongoing and includes remedying unexpected challenges with equipment reliability identified during the first-time implementation of our innovative design and configuration, and reliability testing. We believe such work will need to be completed before certain components operate as intended and the facility can be fully commercially operable, and COD can occur. On March 28, 2023, we submitted to FERC an update regarding commissioning, certain identified reliability challenges, and needed repairs and replacements, which we are working to complete in compliance with FERC’s regulatory requirements. Specifically, we are conducting substantial remediation work on the heat recovery steam generators, or HRSGs, of the power island system where the manufacturer of such equipment, General Electric, implemented a change in method of fabrication that has led to substantial leaking that was identified during commissioning tests. As part of the remediation work, replacement parts for the HRSGs have been manufactured by our contractor by utilizing a proven fabrication method, which we have explicitly required to be used for the Plaquemines Project and Phase 1 of the CP2 Project, and which we expect to require for each project or phase thereof for which we have not executed a power island system purchase order. Among the other ongoing rectification work, our gas pre-treatment units have underperformed and have been unable to pass required performance tests. We continue to engage in remediation efforts with UOP to improve the pre-treatment operations to attain the designed levels of performance and redundancy and pass such required performance tests.

Given the ongoing significant commissioning and remediation work, we are targeting to complete all remediation work and achieve COD in once the project has completed its commissioning process and testing and is capable of safely and reliably producing its designed nameplate levels of LNG volumes.

As of , 2024, the Calcasieu Project executed over million work hours with a TRIR of . This safety performance far exceeds the national average for the industry of 2.1 for 2023.

Commissioning LNG Sales

Due to our unique project configuration (which includes many mid-scale liquefaction trains) and development approach, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-size liquefaction trains. This important reliability and technical requirement has resulted in the production of LNG starting earlier in the construction schedule than at traditional LNG facilities, and in far greater quantities – requiring us to produce a substantial number of commissioning cargos at the Calcasieu Project. Despite the longer than expected commissioning process at the Calcasieu Project due to certain unexpected challenges with equipment reliability that we are in the process of remediating, as of , 2024, the Calcasieu Project had loaded and sold LNG commissioning cargos and received $ billion in gross proceeds ($ billion in net proceeds after deducting net cash paid for natural gas, which primarily includes the net cost of purchasing and transporting feed gas) from such commissioning cargos. A portion of such proceeds are held in cash reserve accounts pursuant to our project financing arrangements and reflected as restricted cash in our financial statements at the Calcasieu Project in an amount we expect to be necessary to complete the project and achieve COD under the Calcasieu Foundation SPAs. As of , 2024, we had an aggregate of $ million of restricted cash in reserve accounts at the Calcasieu Project.

Post-COD Contracts and Excess LNG Sales

We have entered into six 20-year take-or-pay, post-COD SPAs, or the Calcasieu Foundation SPAs, on an FOB basis, which means that the title to the LNG will transfer at the time our customers take delivery at our

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facilities. Consequently, our customers under our FOB SPAs will bear the risk of loss during transport and the cost of shipping the LNG cargo. The Calcasieu Foundation SPAs as summarized below equate to approximately 8.5 mtpa of LNG, which is approximately 85% of the project’s expected nameplate capacity of 10.0 mtpa. The majority of these offtakers have investment grade credit ratings and are among the industry’s strongest financial credits.

LOGO

The obligation to make LNG available under the Calcasieu Foundation SPAs commences from the occurrence of COD, which is an identical requirement for all six SPAs and a typical construct within the LNG industry. Under these six SPAs, customers will purchase LNG from us for a price consisting of a fixed facility charge (a portion of which is subject to an annual adjustment for inflation) per MMBtu of LNG, plus a variable commodity charge equal to 115% of Henry Hub per MMBtu of LNG. In certain circumstances, customers may elect to cancel or suspend deliveries of LNG cargos, but they will still be required to pay the fixed fee (but not the variable commodity charge) with respect to contracted volumes that are not delivered as a result of such cancellation or suspension. The Calcasieu Foundation SPAs and related contracted volumes are not tied to any specific liquefaction trains at the Calcasieu Project. To the extent of any shortfall in supply, we will pay the applicable counterparty to an SPA an amount for shortfall based on: (a) (i) the replacement price for LNG or, in the event a replacement quantity cannot be purchased, the market price of LNG at such time at the cargo’s originally scheduled destination, minus (ii) the contract sales price plus (b) costs (including transportation costs) incurred by such counterparty due to such shortfall, plus (c) costs incurred by such counterparty associated with idling an LNG tanker scheduled to load the shortfall quantity, minus (d) cost savings realized by such counterparty due to the shortfall. This requirement to financially address shortfalls over the 20-year life of the Calcasieu Foundation SPAs underpins the focus on redundancy and reliability to be demonstrated as part of the commissioning phase of construction, prior to achieving COD.

The Calcasieu Foundation SPAs include termination rights in favor of the customer if, among other things, COD did not occur by March 2024, as may be extended in certain circumstances (including, among other things, in connection with a force majeure event). As a consequence of the occurrence of one such force majeure event, as further described below, the deadline for COD in such SPAs would be extended and we currently anticipate that such customers will not be entitled to terminate as a result of failure to designate COD until June 2025. We have notified all of our customers under the Calcasieu Project post-COD SPAs of the anticipated delay to COD, indicating that such delay results from a force majeure event. As a result of such designation, the right of our customers to terminate their respective SPAs for failure to achieve COD within 180 days following a specified window period would be postponed, and we currently anticipate that such customers will not be entitled to

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terminate their contracts as a result of failure to designate COD until June 2025. All of such customers have questioned whether the delay constitutes a force majeure event under the contract, in which case they would have a right to terminate their SPAs, generally for a limited duration of time, if COD did not occur by March 2024. For more information see “Risk Factors—Risks Relating to Our Business—Our customers may terminate our SPAs if certain conditions are not met or for other reasons.” As we continue to commission the facility, we aim to continue to produce commissioning cargos of LNG for export in accordance with all regulatory requirements and subject to the above described HRSG and gas pre-treatment remediation work and other repairs being conducted while the site is made ready for reliability testing.

In addition to such 20-year Calcasieu Foundation SPAs, we have entered into a fixed-price three-year take-or-pay SPA for 1 mtpa of the Calcasieu Project’s expected nameplate capacity with Unipec (a subsidiary of Sinopec) and a fixed-price five-year take-or-pay SPA for 0.5 mtpa of the Calcasieu Project’s expected nameplate capacity with CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd. These shorter-term, post-COD SPAs include similar terms and conditions as the long-term Calcasieu Foundation SPAs and provide supplemental, firm contracted revenues for the benefit of the project. Following expiration of these shorter-term, post-COD SPAs, the corresponding 1.5 mtpa of the expected nameplate capacity can be recontracted by us at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue for the project in future periods.

We expect that any excess LNG produced by the Calcasieu Project above the nameplate capacity of 10.0 mtpa will be sold to VG Commodities under the applicable Intercompany Excess Capacity SPA. LNG sold under this Intercompany Excess Capacity SPA can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing, which is typically higher in the short- to medium-term market, and capture additional revenue on an ongoing basis after COD.

A portion of the Calcasieu Project’s excess capacity that is sold to VG Commodities is already contracted to be resold. VG Commodities is party to an LNG sales and purchase agreement, or the VG Commodities BP SPA, with BP Gas Marketing Limited, or BP, pursuant to which, once COD occurs under the applicable Intercompany Excess Capacity SPA, VG Commodities has contracted to resell at least 50% of the LNG generated by the Calcasieu Project in excess of its nameplate capacity (subject to an annual cap at the option of the buyer). The VG Commodities BP SPA is structured as a 20-year, FOB sales contract, under which BP is required to pay VG Commodities a purchase price for LNG delivered to BP based on a simulated net-back price, which is designed to reflect a profit margin (after deducting related costs) realized from downstream sales of LNG. However, in certain cases, including if an event of default by VG Commodities occurs under the VG Commodities BP SPA, BP is entitled to an assignment of VG Commodities’ rights under the relevant Intercompany Excess Capacity SPA.

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Plaquemines Project



Plaquemines Project	Phase 1	Phase 2

Project location:

Site	Approximately 630 acres in Plaquemines Parish, Louisiana

Property rights	Ground lease for 30 years, with options to extend to 70 years

Deep-water frontage	Approximately 1.3 miles

Project design:

Expected nameplate capacity	13.3 mtpa	6.7 mtpa

Expected peak production capacity	Up to 27.2 mtpa⁽¹⁾

Potential bolt-on expansion incremental capacity	Up to 8.9 mtpa⁽²⁾

Liquefaction system	12 blocks (24 liquefaction trains)	6 blocks (12 liquefaction trains)

LNG storage	2 × 200,000 cubic meter cryogenic LNG storage tanks	2 × 200,000 cubic meter cryogenic LNG storage tanks

Power supply	2 power island systems (each with a capacity of 620 MW nominal / 720 MW peak and consisting of 5 gas turbine generators and 2 steam turbine generators along with related equipment)

Gas pre-treatment system	4 units (1 redundant unit)	2 units (1 incremental redundant unit)

Berths	2 berths, each designed to accommodate vessels up to 200,000 cubic meters in capacity	1 berth, designed to accommodate vessels up to 200,000 cubic meters in capacity

Lateral pipelines	Two laterals (one approximately 15-mile long lateral and one approximately 12-mile long lateral)

Key permits:

FERC approval	24.0 mtpa (September 2019)⁽¹⁾

DOE approval – FTA Nations	27.2 mtpa (June 2022)⁽³⁾

DOE approval – NON-FTA Nations	24.0 mtpa (October 2019)⁽¹⁾

Project timeline:

Final investment decision / financial closing	May 2022	March 2023

(1)	Our request to increase the authorized production capacity and authorized level of exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa is still pending. See “—Governmental Regulation—Federal Energy Regulatory Commission (FERC)—Plaquemines Project.”

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

(3)	Cumulative exports to FTA Nations and Non-FTA Nations cannot exceed the permitted capacity as authorized by the FERC.

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Project Description

We are in an advanced stage of construction for the Plaquemines Project, which is being built in two phases, with an expected nameplate capacity of 20.0 mtpa and, subject to certain regulatory approvals, an expected peak production capacity of 27.2 mtpa, located on approximately 630 acres of land in Plaquemines Parish, with approximately 1.3 miles of deep-water frontage on the Mississippi River. Phase 1 of the project is expected to have a nameplate capacity of 13.3 mtpa and Phase 2 is expected to have a nameplate capacity of 6.7 mtpa. We currently have applications pending with the United States Federal Energy Regulatory Commission, or FERC, and the United States Department of Energy, or DOE, that, if approved, would increase the permitted production capacity and authorized export capacity from 24.0 mtpa to 27.2 mtpa.

The liquefaction system for the Plaquemines Project facility will include 36 mid-scale, factory-built liquefaction trains (18 integrated single mixed refrigerant blocks) and support facilities. As with the Calcasieu Project, each block will contain two liquefaction trains. For each 10 mtpa of its nameplate capacity, the facility will also include three natural gas pre-treatment units to remove water and acid gases from feed gas prior to liquefaction, and two 200,000 cubic meter cryogenic LNG storage tanks. The marine facilities for Phase 1 will include two LNG berthing docks that would accommodate vessels of up to 200,000 cubic meters in capacity, one full nominal 620 MW (720 MW peak) inside the fence, air-cooled combined cycle gas fired power plant and a portion of the power equipment for a second nominal 620 MW power plant. Both pipeline laterals for the combined project have been built as part of Phase 1. Phase 2 adds a third LNG berthing dock and additional inside the fence, air-cooled combined cycle gas fired power capacity. The two power island systems are complemented by two nominal 23 MW LM2500 gas turbines that support frequent cycling and provide back-up power and black start capabilities. Once complete, we believe this technology and our facility design will provide greater operational redundancy and availability, reducing planned and unplanned downtime, lower emissions and enable us to reliably deliver LNG to our customers.

Project Site Real Estate

In July 2021, we entered into a 30-year lease with the Plaquemines Port Harbor and Terminal District, covering the land on which the project is located. This lease may be extended at our option for up to four additional 10-year terms, up to 70 years in the aggregate.

Project Construction and Commissioning

We made our FID for Phase 1 in May 2022 and our FID for Phase 2 in March 2023. As of , 2024, construction of the Plaquemines Project was approximately % complete, based on completion of the 20.0 mtpa expected nameplate capacity, with Phase 1 % complete and Phase 2 % complete.

The Plaquemines Project is being constructed pursuant to two EPC contracts, one per phase, or the Plaquemines EPC Contracts, that we entered into with KZJV, LLC, or KZJV, a limited liability company that is owned by KBR EPC Member and Zachry Industrial. Under the Plaquemines EPC Contracts, Venture Global is responsible for executing or directly managing significant scopes of work. We issued the notice to proceed, or NTP, under the Plaquemines EPC Contract for Phase 1 in May 2022. The NTP for Phase 2 was issued in March 2023. See “—EPC Contracts—Plaquemines EPC Contracts” for additional information on the Plaquemines EPC Contracts.”

Baker Hughes, UOP and CB&I are each providing and constructing the mid-scale, factory-built liquefaction trains and power island systems, the pre-treatment system, and storage tanks, respectively, similar to their scope and terms for the Calcasieu Project. See “—Calcasieu Project” above for more information. As of , 2024, the liquefaction train was delivered to the site. Other recent procurement and construction milestones included . Sunland Construction Inc. was responsible for constructing the Gator Express pipeline that connects the LNG facility to interstate pipelines. The Gator Express pipeline achieved substantial completion in , 2024.

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As of , 2024, we estimate that the total project costs for the Plaquemines Project will be approximately $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs, of which approximately $ billion had been paid for as of , 2024. Our estimated total project cost remaining is based upon our project cost experiences with the Calcasieu Project and with the Plaquemines Project to date and reflects the current inflationary environment. However, the costs to complete the Plaquemines Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. As a result, the actual project costs for the Plaquemines Project may be materially higher than our current estimates. See “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.”

As of , 2024, the Plaquemines Project had executed over million work hours with a TRIR of . This safety performance far exceeds the national average for the industry of 2.1 for 2023.

Commissioning LNG Sales

Although designed to be twice as large as the Calcasieu Project on a nameplate basis, the Plaquemines Project utilizes a similar project configuration and development approach to the Calcasieu Project. In contrast to traditional LNG facilities that are constructed by a single EPC contractor and include substantially fewer, larger-size liquefaction trains, our project design and configuration utilizes pioneering, mid-scale, factory-made liquefaction trains and other discrete systems and equipment, which require an extended commissioning period. Given this longer and gradual commissioning period, which starts with addressing identified operational deficiencies, testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities, we expect to produce a substantial number of commissioning cargos. This production occurs during the period in which additional components of the relevant phase are brought into operation, completed and tested (including, if necessary, performing completion and rectification work to address unexpected performance deficiencies), to ensure the project is completed and achieves the performance levels necessary for stable, reliable long-term operations to supply LNG under the project’s post-COD SPAs. As of , 2024, the Plaquemines Project had loaded and sold LNG commissioning cargos and received $ billion in gross proceeds ($ billion in net proceeds after deducting net cash paid for natural gas, which primarily includes the net cost of purchasing and transporting feed gas) from such commissioning cargos.

Post-COD Contracts and Excess LNG Sales

As of , 2024, we have entered into twelve 20-year take-or-pay, post-COD SPAs in connection with the Plaquemines Project, or the Plaquemines Foundation SPAs. The Plaquemines Foundation SPAs, as summarized in the chart below, equate to approximately 19.7 mtpa of LNG, which is approximately 98.5% of the project’s expected nameplate capacity of 20.0 mtpa. The majority of these offtakers have investment grade credit ratings and are among the industry’s strongest financial credits.

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LOGO

The obligation to make LNG available under these SPAs commences from the occurrence of COD, which is bifurcated by Phase 1 or Phase 2, depending on the SPA. All of these SPAs are structured to be delivered on an FOB basis, with the exception of one Phase 1 SPA for 1.2 mtpa, which is structured to be delivered on a DPU basis – requiring us to ship, deliver, and unload LNG to our customer’s designated import facility. The pricing structure and contractual obligations in the Plaquemines Foundation SPAs substantially mirrors the Calcasieu Foundation SPAs. See “—Calcasieu Project” for more information. Similar to the Calcasieu Foundation SPAs, the Plaquemines Foundation SPAs include termination rights in favor of the customer if, among other things, COD does not occur by May 2027 or March 2028 for the Phase 1 and Phase 2 SPA, respectively, as may be extended in certain circumstances (including, among other things, in connection with a force majeure event).

In addition to the Plaquemines Foundation SPAs, we have entered into a short-term, post-COD SPA for 0.3 mtpa of the Plaquemines Project’s expected nameplate capacity with Inpex Energy Trading Singapore Pte. Ltd. on an FOB basis. This shorter-term, post-COD SPA includes similar terms and conditions as the Plaquemines Foundation SPAs and provides supplemental, firm contracted revenues for the benefit of the project. After the expiry of such SPA, such 0.3 mtpa can be recontracted by us at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue for the project.

Any excess LNG produced by the Plaquemines Project above the nameplate capacity of 13.3 mtpa for Phase 1 or above the nameplate capacity of 6.7 mtpa for Phase 2 will be sold to VG Commodities under the applicable Intercompany Excess Capacity SPA (one per phase). LNG sold under such Intercompany Excess Capacity SPAs can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue on an ongoing basis after COD for each of Phase 1 and Phase 2, at price levels that we expect will typically exceed the fixed fee prices secured under the Plaquemines Foundation SPAs.

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CP2 Project


CP2 Project	Phase 1	Phase 2

Project location:

Site	Approximately 1,150 acres in Cameron Parish, Louisiana

Property rights	Ground leases for 30 years, with options to extend to 70 years

Deep-water frontage	Approximately 1.0 mile

Anticipated project design:⁽¹)

Expected nameplate capacity	14.4 mtpa	5.6 mtpa

Expected peak production capacity	Up to 28.0 mtpa

Potential bolt-on expansion incremental capacity	Up to 14.0 mtpa⁽²⁾

Liquefaction system	13 blocks (2 liquefaction trains per block)	5 blocks (2 liquefaction trains per block)

LNG storage	2 × 200,000 cubic meter cryogenic LNG storage tanks	2 × 200,000 cubic meter cryogenic LNG storage tanks

Power supply	2 power island systems (each with a capacity of 620 MW nominal / 720 MW peak and consisting of 5 gas turbine generators and 2 steam turbine generators along with related equipment)

Gas pre-treatment system	4 units (1 redundant unit)	2 units (1 incremental redundant unit)

Berths	2 berths, each designed to accommodate vessels up to 200,000 cubic meters in capacity

Lateral pipelines	Two laterals (one approximately 6-mile long lateral and one approximately 85-mile long lateral)

Key permits:

FERC approval	June 2024

DOE approval – FTA Nations	28.0 mtpa (April 2022)

DOE Non-FTA Nations	Application filed December 2021 (pending approval)

Project timeline:

Targeted DOE approval – Non-FTA Nations export application

Targeted final investment decision / financial closing

Targeted COD

(1)	Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors.

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

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Project Description

Our third project, the CP2 Project, is in an advanced stage of engineering, with major procurement work, and off-site manufacturing of key modules and equipment underway. The CP2 Project is designed as a natural gas liquefaction and export facility that will be built in two distinct phases, with an expected nameplate capacity of 20.0 mtpa and an expected peak production capacity of 28.0 mtpa. The project will be located adjacent to the Calcasieu Project on approximately 1,150 acres of land in Cameron Parish, with approximately 1 mile of deep-water frontage on the Calcasieu Ship Channel. Phase 1 of the project is anticipated to comprise 14.4 mtpa nameplate capacity and Phase 2 is anticipated to comprise 5.6 mtpa nameplate capacity.

Project Site Real Estate

In 2019, we entered into a 30-year lease (with extension rights) covering approximately 351 acres of land on which the CP2 Project will be located. In October 2023, we exercised our rights under various option agreements with respect to an additional 718 acres of land on which the CP2 Project will be located or will be adjacent to. These leases have up to four additional ten-year terms, up to 70 years in the aggregate, similar to leases for the Calcasieu Project and the Plaquemines Project. We acquired fee simple ownership to approximately 27 acres of the project site in 2023.

Project Engineering, Procurement, and Construction

We have already completed substantial engineering, procurement, manufacturing and off-site construction work for the CP2 Project in advance of a final investment decision, which remains subject to certain regulatory approvals and market conditions. See “—Governmental Regulation” and “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

As of , 2024, engineering work for Phase 1 of the CP2 Project was % complete and we had incurred an aggregate of approximately $ billion of costs for various engineering, procurement, manufacturing, and other activities to support the project. Engineering completion percentage is a key driver of schedule and budget fidelity during project construction and execution. In April 2023, we entered into a liquefaction train system purchase order with Baker Hughes for Phase 1 of the CP2 Project and we issued full NTP in September 2023. In May 2023, we entered into an EPC Contract for construction of Phase 1 of the CP2 Project, or the CP2 Phase 1 EPC Contract, with Worley Field Services Inc., or Worley, and have issued several limited notices to proceed thereunder. See “EPC Contracts—CP2 Phase 1 EPC Contract” for additional information on the CP2 Phase 1 EPC contract. In June 2023, we entered into an engineering, procurement, and construction contract with CB&I for the Phase 1 storage tanks under similar terms as for the LNG tanks built at our Calcasieu Project and Plaquemines Project. We issued certain limited notices to proceed to CB&I in June 2023 and November 2023. In July 2023, we entered into a power island system purchase order with Baker Hughes for Phase 1 of the CP2 Project and we issued full NTP in September 2023. We plan to select our remaining engineering, procurement, and construction contractors based on competitive bid procurement processes and strict adherence to requiring the highest quality of work.

We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to the Calcasieu Project and the Plaquemines Project. However, we anticipate that we will seek to manage additional scopes of work directly at the CP2 Project and the other projects we develop in the future. Specifically, we anticipate that we will perform additional EPCM activities and deploy labor that we recruit to leverage lessons learned and the relationships fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project, which we believe will help improve construction efficiency and reduce total costs for the CP2 Project.

As of , 2024, we estimate that the total project costs for the CP2 Project will range between approximately $ and $ billion, including EPC contractor profit and contingency, owners’ costs

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and financing costs, substantially all of which has yet to be funded. Our estimated total project cost is based upon our project cost experiences with the Calcasieu Project and the Plaquemines Project and reflects the current inflationary environment and that the CP2 Project’s pipelines are expected to be longer than the pipelines for the Calcasieu Project and the Plaquemines Project. However, we have not yet entered into an EPC Contract for Phase 2 of the CP2 Project or certain other key contracts for the development and construction of the CP2 Project. As a result, there can be no assurance that we will be able to enter into such contracts on similar terms to those for the Calcasieu Project, the Plaquemines Project, and/or Phase 1 of the CP2 Project, as applicable. In addition, certain regulatory approvals and permits must be obtained on a timely basis in order to construct and operate the project, and there can be no assurance that we can obtain and maintain the necessary regulatory approvals and permits to complete the CP2 Project on the anticipated schedule. Accordingly, the actual project costs for the CP2 Project may be materially higher than this estimate. Moreover, the anticipated costs to achieve completion of the CP2 Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors, including delays in construction or commissioning of the project or the execution of any repair or warranty work and change orders under or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for the CP2 Project, and/or other construction or supply contracts resulting from the occurrence of certain specified events that may give the applicable contractor or supplier the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. See “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.”

Subject to regulatory approvals and market conditions, we are currently targeting final investment decision forPhase 1 of the CP2 Project in and for Phase 2 of the CP2 Project in .

Commissioning LNG Sales

The CP2 Project is designed to utilize a similar project configuration and development approach as the Calcasieu Project and the Plaquemines Project. In contrast to traditional LNG facilities that are constructed by a single EPC contractor and include substantially fewer, larger-size liquefaction trains, our project design and configuration utilizes pioneering, mid-scale, factory-made liquefaction trains and other discrete systems and equipment, which require an extended commissioning period. Given this longer and gradual commissioning period, which starts with testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities, we expect to produce a substantial number of commissioning cargos. This production occurs during the period in which additional components of the relevant phase are brought into operation, completed and tested (including, if necessary, performing completion and rectification work to address unexpected performance deficiencies), to ensure the project is completed and achieves the performance levels necessary for stable, reliable long-term operations to supply LNG under the project’s post-COD SPAs. Based on the current engineering, procurement and pre-FID investments that we have made to advance the CP2 Project, we believe that the CP2 Project has the potential to produce LNG and load its first commissioning cargos earlier in the construction timeline and in greater quantities than our prior projects, based on the continual construction optimization techniques we have gained from installing and commissioning our numerous mid-scale liquefaction trains at the Calcasieu Project and the Plaquemines Project.

Post-COD Contracts and Excess LNG Sales

As of , 2024, we have entered into eight 20-year take-or-pay, post-COD SPAs in connection with the CP2 Project, or the CP2 Foundation SPAs, on an FOB basis.

These SPAs, as summarized below, all relate to Phase 1 of the CP2 Project and equate to 9.25 mtpa of LNG, which is approximately 64% of the expected nameplate capacity for Phase 1 of 14.4 mtpa. The majority of these offtakers have investment grade credit ratings and are among the industry’s strongest financial credits and include supermajors and nation state sponsored enterprises.

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LOGO

The obligation to make LNG available under these SPAs commences from the occurrence of COD. All of these SPAs are structured for delivery on an FOB basis. The pricing structure and contractual obligations in the CP2 Foundation SPAs are substantially similar to the Calcasieu Foundation SPAs and the Plaquemines Foundation SPAs. See “—Calcasieu Project” for further information. Similar to the Calcasieu Foundation SPAs, the CP2 Foundation SPAs include termination rights in favor of the customer if certain conditions precedent are not satisfied by us or waived by the customer by a date certain in , including that we receive all LNG export authorizations by that date. As a result, some of our customers under the CP2 Foundation SPAs may decide to terminate their SPAs if such future deadlines pass because of the temporary pause on new authorizations of natural gas exports to Non-FTA Nations described below under “—Governmental Regulation—DOE Export Authorizations.” See ”Risk Factors—Risks Relating to Our Business—Our customers may terminate our SPAs if certain conditions are not met or for other reasons.” As of , 2024, no customer was entitled to terminate its CP2 Foundation SPA for failure to satisfy conditions precedent. In addition, our customers also have other limited termination rights if, among other things, COD for Phase 1 does not occur by a date that is approximately 60 months from the satisfaction of such conditions precedent, as may be extended in certain circumstances (including, among other things, in connection with a force majeure event).

We expect that any excess LNG produced by the CP2 Project above the nameplate capacity of 14.4 mtpa for Phase 1 or above the nameplate capacity of 5.6 mtpa for Phase 2 will be sold to VG Commodities under an Intercompany Excess Capacity SPA (one per phase) to be entered into for the relevant phase. LNG sold under such Intercompany Excess Capacity SPAs can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue on an ongoing basis after COD for each of Phase 1 and Phase 2.

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CP3 Project


CP3 Project	Phase 1	Phase 2

Project location:

Site	Approximately 840 acres in Cameron Parish, Louisiana

Property rights	Ground lease for up to 70 years in total

Deep-water frontage	Approximately 1 mile

Anticipated project design⁽¹⁾:

Expected nameplate capacity	30.0 mtpa (phase and plant configuration remains to be determined)

Expected peak production capacity	Up to 42.0 mtpa

Anticipated project timeline⁽¹⁾:

Pre-filing with FERC

Targeted final investment decision / financial closing

Targeted COD

(1)

Anticipated based on capacity, scale, location and infrastructure, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors. As of , 2024, no FERC and no DOE filings have been made and the necessary approvals for the CP3 Project have not been obtained. Accordingly, this is a target only, based on, among other things, anticipated timeframes for the receipt of the required DOE and FERC approvals. See “—Governmental Regulation” and “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

Project Description

Our fourth project, the CP3 Project, is in the development stage and is designed as a natural gas liquefaction and export facility to be built in two distinct phases, with an expected nameplate capacity of 30.0 mtpa and an expected peak production capacity of 42.0 mtpa. We plan to locate the CP3 Project nearby the Calcasieu Project and the CP2 Project on approximately 840 acres of land in Cameron Parish, with approximately 1.0 mile of deep-water frontage on the Calcasieu Ship Channel.

Project Site Real Estate

In 2023, we entered into a 30-year lease (with extension rights) covering approximately 840 acres of land on which the CP3 Project will be located on or adjacent to. This lease may be extended at our option for up to four additional 10-year terms, up to 70 years in the aggregate.

Project Development

As of , 2024, we have completed significant regulatory filings and related engineering studies and simulations, including certain marine berth simulations.

As of , 2024, we initiated the pre-filing process for the CP3 Project with FERC. As of , 2024, we have not yet entered into definitive agreements with an EPC contractor or other key advisors and contractors necessary for the project’s development and construction. However, we have ample capacity under the Baker Hughes Master Agreement to contract for the potential supply of liquefaction trains and power island

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systems, which we expect to utilize for the CP3 Project. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects.

As of , 2024, we estimate that the total project costs for the CP3 Project will range between approximately $ and $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs, substantially all of which has yet to be funded. Our estimated total project cost is based upon our project cost experiences with the Calcasieu Project and the Plaquemines Project and reflects the current inflationary environment and that the CP3 Project’s pipelines are expected to be longer than the pipelines for the Calcasieu Project and the Plaquemines Project. However, we have not yet entered into an EPC contract or other key contracts for the development and construction of the CP3 Project. As a result, there can be no assurance that we will be able to enter into such contracts on similar terms to those for our initial projects. We have not yet prepared or submitted applications for key project permits or approvals. In addition, certain regulatory approvals and permits must be obtained on a timely basis in order to construct and operate the project, and there can be no assurance that we can obtain and maintain the necessary regulatory approvals and permits to complete the CP3 Project on the anticipated schedule. Accordingly, the actual project costs for the CP3 Project may be materially higher than this estimate. See “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.”

Subject to regulatory approvals and market conditions, we are currently targeting final investment decision forPhase 1 of the CP3 Project in and Phase 2 of the CP3 Project targeted in . We expect Phase 2 of the CP3 Project to commence construction approximately months following the commencement of construction of Phase 1 and full commercial operations for Phase 2 approximately months following the commencement of full commercial operations of Phase 1.

Potential LNG Sales

We expect that the CP3 Project will utilize a similar project configuration, development approach, and reliability testing process as our initial projects. In contrast to traditional LNG facilities that are constructed by a single EPC contractor and include substantially fewer, larger-size liquefaction trains, our project design and configuration utilizes pioneering, mid-scale, factory-made liquefaction trains and other discrete systems and equipment, which require an extended commissioning period. Given this longer and gradual commissioning period, which starts with testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities, we anticipate that we will produce a substantial number of commissioning cargos. This production occurs during the period in which additional components of the relevant phase are brought into operation, completed and tested (including, if necessary, performing completion and rectification work to address unexpected performance deficiencies), to ensure the project is completed and achieves the performance levels necessary for stable, reliable long-term operations to supply LNG under the various post-COD SPAs that we anticipate entering into. While we have not yet entered into any LNG SPAs for the CP3 Project, we aim to market and sell the nameplate capacity at the CP3 Project under a combination of long-term 20-year SPAs as well as and short- and medium-term contracts to optimize the average fixed facility charge across our SPAs. Any excess LNG produced by the CP3 Project above the nameplate capacity for Phase 1 or above the nameplate capacity for Phase 2 is expected to be sold to VG Commodities under an Intercompany Excess Capacity SPA to be entered into for the relevant phase. LNG sold under such Intercompany Excess Capacity SPAs can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue on an ongoing basis after COD of Phase 1 and Phase 2.

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Delta Project


Delta Project	Phase 1	Phase 2

Project location:

Site	Approximately 1,100 acres in Plaquemines Parish, Louisiana

Property rights	Option to lease for up to 70 years

Deep-water frontage	Approximately 0.6 miles

Anticipated project design⁽¹⁾:

Expected nameplate capacity	24.4 mtpa (phase and plant configuration remains to be determined)

Expected peak production capacity	Up to 34.2 mtpa

Potential bolt-on expansion incremental capacity	Up to 7.8 mtpa⁽²⁾

Anticipated project timeline⁽¹⁾:

Pre-filing with FERC	April 2019

Targeted final investment decision / financial closing

Targeted COD

(1)

Anticipated based on capacity, scale, location and infrastructure, and may change based on design considerations, regulatory review process, engagement with contractors, and other factors. As of , 2024, final FERC and DOE filings have not been made and the necessary approvals for the Delta Project have not been obtained. Accordingly, this is a target only, based on, among other things, anticipated timeframes for the receipt of the required DOE and FERC approvals. See “—Governmental Regulation” and “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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

Project Description

Our fifth project, the Delta Project, is in the development stage and is designed as a natural gas liquefaction and export facility to be built in two distinct phases, with an expected nameplate capacity of 24.4 mtpa and an expected peak production capacity of 34.2 mtpa. We plan to locate the Delta Project adjacent to the Plaquemines Project on approximately 1,100 acres of land in Plaquemines Parish, with approximately 0.6 miles of deep-water frontage on the Mississippi River.

Project Site Real Estate

Under our option agreements with the landowner of the Plaquemines Project and Delta Project sites, we have lease option agreements to lease up to approximately 1,100 acres of land for the Delta Project under substantially similar terms as our existing lease for the Plaquemines Project.

Project Development

As of , 2024, we have completed significant regulatory filings and related engineering studies and simulations, including certain marine berth simulations.

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While we initiated the pre-filing process for the Delta Project with FERC in April 2019, we have not yet entered into definitive agreements with an EPC contractor or other key advisors and contractors necessary for the project’s development and construction. However, we have ample capacity under the Baker Hughes Master Agreement to contract for the potential supply of liquefaction trains and power island systems, which we expect to utilize for the Delta Project. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects.

As of , 2024, we estimate that the total project costs for the Delta Project will range between approximately $ and $ billion, including EPC contractor profit and contingency, owners’ costs and financing costs, substantially all of which has yet to be funded. Our estimated total project cost is based upon our project cost experiences with the Calcasieu Project and the Plaquemines Project and reflects the current inflationary environment and that the Delta Project’s pipelines are expected to be materially longer than the pipelines for the Calcasieu Project and the Plaquemines Project. However, we have not yet entered into an EPC contract or other key contracts for the development and construction of the Delta Project. As a result, there can be no assurance that we will be able to enter into such contracts on similar terms to those for the Calcasieu Project, the Plaquemines Project, and/or Phase 1 of the CP2 Project, as applicable. In addition, certain regulatory approvals and permits must be obtained on a timely basis in order to construct and operate the project, and there can be no assurance that we can obtain and maintain the necessary regulatory approvals and permits to complete the Delta Project on the anticipated schedule. Accordingly, the actual project costs for the Delta Project may be materially higher than this estimate. See “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.”

Subject to regulatory approvals and market conditions, we are currently targeting final investment decision forPhase 1 of the Delta Project in and Phase 2 of the Delta Project in . We expect Phase 2 of the Delta Project to commence construction approximately months following the commencement of construction of Phase 1, and full commercial operations for Phase 2 approximately months following the commencement of full commercial operations of Phase 1.

Potential LNG Sales

We expect that the Delta Project will utilize a similar project configuration, development approach, and reliability testing process as our initial projects. In contrast to traditional LNG facilities that are constructed by a single EPC contractor and include substantially fewer, larger-size liquefaction trains, our project design and configuration utilizes pioneering, mid-scale, factory-made liquefaction trains and other discrete systems and equipment, which require an extended commissioning period. Given this longer and gradual commissioning period, which starts with testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities, we anticipate that we will produce a substantial number of commissioning cargos. This production occurs during the period in which additional components of the relevant phase are brought into operation, completed and tested (including, if necessary, performing completion and rectification work to address unexpected performance deficiencies), to ensure the project is completed and achieves the performance levels necessary for stable, reliable long-term operations to supply LNG under the various post-COD SPAs that we anticipate entering into. While we have not yet entered into any LNG SPAs for the Delta Project, we aim to market and sell the nameplate capacity at the Delta Project under a combination of long-term 20-year SPAs as well as and short- and medium-term contracts to optimize the average fixed facility charge across our SPAs. Any excess LNG produced by the Delta Project above the nameplate capacity for Phase 1 or above the nameplate capacity for Phase 2 is expected to be sold to VG Commodities under an Intercompany Excess Capacity SPA to be entered into for the relevant phase. LNG sold under such Intercompany Excess Capacity SPAs can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, providing the flexibility to optimize pricing and capture additional revenue on an ongoing basis after COD of Phase 1 and Phase 2.

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Key, Complementary Assets

Natural Gas Supply and Transportation

Natural Gas Supply Portfolio Approach

To the extent we produce LNG for export pursuant to our existing SPAs, we are responsible for procuring natural gas and transporting it to the relevant facility for liquefaction. We have entered into a portfolio of natural gas supply agreements with domestic natural gas suppliers to supply feed gas to the Calcasieu Project and the Plaquemines Project, which we continue to expand to suit the needs of our projects. We also anticipate entering into long-term natural gas supply arrangements with large upstream gas producers that will integrate their gathering and processing facilities into our planned pipeline network and deliver natural gas to our project facilities for liquefaction. Assuming we are able to operate our projects at their expected peak production capacity, we anticipate that we will require approximately 1.9 Bcf/d of natural gas for the Calcasieu Project, 4.2 Bcf/d of natural gas for the Plaquemines Project, 4.3 Bcf/d of natural gas for the CP2 Project, 6.5 Bcf/d of natural gas for the CP3 Project, and 5.3 Bcf/d of natural gas for the Delta Project. We have constructed lateral pipelines to connect the Calcasieu Project and the Plaquemines Project to the ANR Pipeline Company, Texas Eastern Transmission LP, and Sabine Pipe Line systems, and the Columbia Gulf, Texas Eastern Transmission LP, and Tennessee Gas Pipeline systems, respectively. Similarly, we intend to construct pipelines to connect our current development projects and any other future projects we may seek to develop to major interstate and intrastate pipelines. In addition, as described below, we aim to own other natural gas pipelines that support or, when constructed, will support our production facilities. Such connections allow us to access highly liquid upstream supplies.

Under our long-term supply agreements, we seek to contract natural gas for basis discounts to the Henry Hub index which can help secure natural gas availability and reduce our long-term exposure to volatility in natural gas prices. Our projects are near several major interstate and intrastate pipelines and are close to one of the more robust and liquid gas trading areas (i.e., Henry Hub) for pipeline quality natural gas in the United States. We believe that these project locations provide numerous low-cost natural gas supply options for our projects, including onshore and offshore resource plays and natural gas storage facilities, resulting in greater reliability and optionality for sourcing our natural gas supply.

Natural Gas Transportation: Contracted Pipeline Capacity and Pipeline Development

We are developing, permitting, constructing and securing transport capacity agreements for midstream natural gas pipeline infrastructure that is intended to support our liquefaction growth strategy and help ensure stable and cost-effective access to the natural gas that fuels our LNG exports.

We have entered into a number of transport capacity agreements and related service agreements with interstate pipeline companies to provide the natural gas transportation to the Calcasieu Project and the Plaquemines Project. The Calcasieu Project and the Plaquemines Project were each sited and sized to facilitate ready connectivity to existing natural gas pipeline network infrastructure with the construction of short-run lateral pipelines. These lateral pipelines (the TransCameron Pipeline and the Gator Express Pipeline), and the major, third-party interstate pipelines to which they are connected, provide natural gas supply primarily from two major shale formations – the Haynesville and the Marcellus/Utica plays – though there is access to other US shale basins though interconnects into the third-party interstate pipelines.

Our existing gas transportation agreements for the Calcasieu Project and the Plaquemines Project are long-term commitments of approximately 20 years from the commencement of service, with extension rights following the initial term.

We have acquired all of the land rights required to construct and operate the TransCameron Pipeline and the Gator Express Pipeline for the Calcasieu Project and the Plaquemines Project. We are also currently in the

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process of securing servitudes, rights of way, crossing agreements, and any permits necessary for us to construct the interstate and intrastate pipelines discussed below, lateral pipelines and related infrastructure required to interconnect the CP2 Project, the CP3 Project and the Delta Project with existing interstate and intrastate natural gas pipeline system.

The TransCameron Pipeline is the lateral pipeline that delivers natural gas to the Calcasieu Project. The Calcasieu Project holds firm transport capacity of 2.35 TBtu/day on several pipeline systems delivering into its TransCameron supply header system including ANR Pipeline Company, Texas Eastern Transmission LP, and Sabine Pipe Line systems. Additionally, the Calcasieu Project holds firm transport capacity of 700,000 Dth/d, reducing to 625,000 Dth/d in April 2025, on the TC Louisiana Intrastate Pipeline, providing the ability to transport Haynesville production into ANR Pipeline for both supply security and beneficial pricing. The TransCameron Pipeline achieved substantial completion in April 2021 and final completion in July 2021 and has been commissioned and placed in service by FERC.

The Gator Express Pipeline is the lateral pipeline that delivers natural gas to the Plaquemines Project. The Plaquemines Project holds firm transport capacity of 4.225 TBtu/day on several pipeline systems delivering into its Gator Express supply header system including Columbia Gulf, Texas Eastern Transmission LP, and Tennessee Gas Pipeline systems. Additionally, the Plaquemines Project holds firm transport capacity of 575,000 Dth/d on the TC Louisiana Intrastate Pipeline, providing the ability to transport Haynesville production into Columbia Gulf for both supply security and beneficial pricing. The Gator Express Pipeline achieved substantial completion in , 2024.

The proposed CP Express Pipeline will consist of 85.4 miles of 48-inch-diameter natural gas pipeline in Jasper and Newton Counties, Texas and Calcasieu and Cameron Parishes, Louisiana, and a 6.0-mile-long, 24-inch-diameter lateral off that mainline in northwest Calcasieu Parish. For the CP Express Pipeline we have secured an agreement, subject to FID of the CP2 Project, for firm transport capacity on the TC Louisiana Intrastate Pipeline LLC (1.4 TBtu/day expanding to 1.9 TBtu/day) to transport Haynesville production into CP Express in Louisiana. In addition, subject to CP2 Project requirements, we expect CP Express will interconnect with additional upstream pipeline infrastructure that secures delivery of gas from additional production basins.

We are in the development and siting process to optimize the plans for the pipelines to support the CP3 Project and the Delta Project.

As we are expanding our development footprint with the CP2 Project, the CP3 Project and the Delta Project, these projects’ production capacities are anticipated to require natural gas volumes that will support the construction of longer interstate and intrastate pipelines that provide incremental access and delivery capability from the Permian, Haynesville, Western Haynesville, Eagle Ford and mid-continent shale formations.

We plan to construct significant 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. For example, we are in the advanced stages of development to establish complementary gas transportation for our development projects. We have partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, and entered into a joint development agreement with WhiteWater Blackfin Holdings, LLC, through our wholly-owned subsidiary Venture Global Midstream Holdings, LLC. Under this agreement, we have committed to jointly develop, permit and site the 190 mile Blackfin pipeline project, which upon construction is expected to include a long-haul 48-inch intrastate pipeline designed to facilitate the transportation of Permian sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline. Subject to the closing of the transactions contemplated by our joint development agreement with WhiteWater Blackfin Holdings, LLC, we expect to secure firm transport capacity on Matterhorn Express Pipeline, LLC (2.0 TBtu/day, expanding to 3.3 TBtu/day). The requisite pipeline and compression equipment for the Blackfin pipeline has been procured under contracts with Borusen Berg Pipe and Solar Turbines, a subsidiary of Caterpillar, and construction is anticipated to

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commence in , 2024. As of , 2024, we have acquired miles of pipeline materials and secured compression capacity to support the development and construction of the Blackfin pipeline.

LNG Tanker Fleet

In order to vertically integrate our business and expand our customer base to premium markets that have limited or no LNG transportation resources, we have contracted to acquire and charter a fleet of at least eleven LNG takers to build out our shipping portfolio. We plan to utilize such LNG tankers, when delivered, to help us manage the considerable volume of potential commissioning cargos produced during facility commissioning, sell excess capacity on a delivered basis and service our single existing post-COD DPU SPA and any future DPU SPAs, which would require us to ship, deliver, and unload LNG to a customer’s designated import facility.

As of , 2024, we have entered into purchase contracts to acquire nine LNG tankers, which are being constructed by two of the premier shipbuilders in South Korea, with two LNG tankers having already been delivered. The remaining LNG tankers are under construction and are scheduled to be delivered on a rolling basis through 2026. As of , 2024, an aggregate of approximately $ remains payable under such purchase contracts through the final delivery of the LNG tankers, subject to certain adjustments set forth in the contracts. Each contract requires payment be made to the counterparty in a fixed number of installments, which are due upon satisfaction of certain milestones in the construction process (of which approximately $ billion have been paid as of , 2024), with the final payment due on the date of delivery of the applicable LNG tanker.

To supplement our LNG tanker acquisitions, we have entered into two short-term charters for additional LNG tankers to facilitate commissioning cargo sales, provide additional operational flexibility, and expand LNG marketing opportunities. Such chartered LNG tankers were delivered to us in August and September 2024. We anticipate that we may seek to enter into similar arrangements from time to time in the future, as needed.

We believe these LNG tankers will help optimize LNG marketing and sales activities, and thereby can help improve our profit margin and differentiate us from other LNG exporters in North America, many of which are not pursuing a strategy to obtain or contract for shipping capacity. Utilizing our fleet, we can also service customers that lack access to shipping capacity and are solely reliant on costly intermediaries for deliveries.

LNG Regasification Capacity

We are pursuing opportunities to secure LNG regasification capacity in key import markets to support current and prospective customers and differentiate ourselves from other LNG exporters in North America. As part of this initiative, through our wholly-owned subsidiary, VG LNG Marketing, LLC, we have acquired firm regasification facility capacity at the largest LNG regasification terminal in Europe, Grain LNG in the United Kingdom. We have contracted to import 42 LNG cargos per year beginning, depending on the starting period, anytime between October 1, 2029 to April 1, 2030, to and until July 14, 2045, except for the period from April 1, 2030 to September 30, 2030, when only 13 LNG cargos can be imported. The annual capacity charge payment under this contract begins on COD of the usage of the terminal (currently scheduled for October 2029). This agreement may be terminated by the terminal operator in certain circumstances, including if we fail to maintain sufficient credit, which failure would result in an obligation to pay a termination penalty. Additionally, we have secured approximately 1 mtpa of LNG regasification capacity at the new Alexandroupolis LNG receiving terminal in Greece for five years, beginning in 2025. Our capacity will account for approximately 25% of the total terminal capacity at Alexandroupolis, or approximately 12 cargos annually.

We aim to use these contracted capacities to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers. In addition, we regularly explore similar regasification capacity opportunities in other markets. We believe our regasification access will allow us to offer spot and term customers a differentiated service, ultimately positioning us to win market share.

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Major Consultants and Contractors

In conjunction with our owner-led procurement and management approach, we are working with a team of consultants and contractors that assist us with the development, engineering, financing, construction, permitting, marketing and operation of our projects. The conventional approach utilized by developers for large-scale projects typically relies on a single, comprehensive EPC contract, delegating all or substantially all responsibility to construct a project to a single EPC contractor. In contrast, we decentralize the contracting approach for our projects and seek to manage key scopes of work directly with a collection of key contractors, each of which are experts in particular systems and equipment.

To implement our “design one, build many” approach, we have entered into the Baker Hughes Master Agreement that grants us the option to order significant quantities of liquefaction trains and power island systems for the projects that we develop. For each of our projects we also enter into certain design, procurement, and construction contracts for other key equipment and facilities such as the pre-treatment system, LNG storage tanks, perimeter wall, and marine facilities. As of , 2024, we have entered into the Calcasieu EPC Contract, the Plaquemines EPC Contracts, the CP2 Phase 1 EPC Contract, the Baker Hughes Master Agreement, purchase orders with Baker Hughes, and several construction or procurement contracts for other key equipment and components of the Calcasieu Project, the Plaquemines Project and the CP2 Project. To the extent not yet in place, we aim to negotiate and to enter into agreements on similar terms to those for the Calcasieu Project and the Plaquemines Project for the construction of our development projects.

Baker Hughes

The Baker Hughes Master Agreement provides for the supply of substantial incremental nameplate liquefaction and power equipment well in excess of the expected 104.4 mtpa nameplate capacity of our current project portfolio. Subject to our compliance with the Baker Hughes Master Agreement, such incremental equipment can be utilized for our development projects and any bolt-on expansions or additional projects that we may seek to develop in the future. Under the Baker Hughes Master Agreement, Baker Hughes is required to supply such equipment at an agreed upon price and schedule with reserved manufacturing capacity.

Purchase orders under the Baker Hughes Master Agreement contain terms and conditions, scope of supply, delivery schedule and performance tests and performance guarantees. We are limited under this agreement from contracting with an alternate equipment supplier to Baker Hughes, even in the event our preference is to do so. All of the liquefaction purchase orders and power island system purchase orders for the Calcasieu Project, the Plaquemines Project, and Phase 1 of the CP2 Project follow the terms and conditions specified in the applicable form purchase order included in the Baker Hughes Master Agreement.

Under the Baker Hughes Master Agreement and related purchase orders, Baker Hughes has committed to satisfy key performance, reliability and LNG quality guarantees for the liquefaction and, as applicable, power equipment it supplies. In particular, if the relevant equipment fails to pass specified performance tests, then Baker Hughes is required to perform all work necessary to cause those systems to successfully pass the performance tests at its own expense or pay liquidated damages under certain performance guarantees.

Baker Hughes has agreed to reserve dedicated manufacturing capacity for the required components for our projects, which is sufficient to cover our five existing and contemplated projects, as well as incremental capacity that can be utilized for bolt-on expansions or future projects. The obligation to reserve manufacturing capacity expires in a staggered manner if we do not execute definitive purchase orders for the applicable portions of these components by certain mutually agreed dates. We have already executed the necessary purchase orders for the Calcasieu Project, the Plaquemines Project, and Phase 1 of the CP2 Project and, based on our anticipated project schedule and barring unforeseen delays, we currently expect that we will be in a position to deliver the purchase orders for Phase 2 of the CP2 Project, the CP3 Project, and the Delta Project to Baker Hughes by the applicable deadlines in the Baker Hughes Master Agreement, as those deadlines may be amended from time to time.

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In addition to the reservation of manufacturing capacity, the Baker Hughes Master Agreement contains an agreed-upon price structure and schedule for the equipment that Baker Hughes is obligated to supply, except for certain alternative configurations of power island systems, in which case the agreed-upon price structure and schedule is adjusted. The Baker Hughes Master Agreement generally provides for various staggered delivery dates for the first delivery of components, subject to the determination of final technical details of the equipment supplied as well as the terms of their respective purchase orders. Furthermore, we and Baker Hughes have agreed upon the pricing framework for the various components required for our liquefaction systems, which remain subject to adjustments based on changes to the scope of equipment and/or operations, negotiations in good faith and/or other modifications pursuant to the terms and conditions of the purchase orders when delivered.

The Baker Hughes Master Agreement includes pre-negotiated forms of purchase orders for the supply of liquefaction systems and power plants. Each purchase order is required to contain terms and conditions, scope of supply, delivery schedule and performance tests and performance guarantees. Unless and until we execute purchase orders for the equipment and issue notices to proceed under those orders, neither we nor Baker Hughes has any binding obligations with respect to the supply of any equipment under the Baker Hughes Master Agreement. Once we execute any purchase order with Baker Hughes for the supply of equipment, we may terminate that purchase order at our discretion. However, if we do terminate any purchase order, we are required to pay a termination fee to Baker Hughes, which is intended to reflect the out-of-pocket costs that Baker Hughes expects to incur in connection with such termination that it is not able to mitigate. As a result, if termination occurs in the mid-to-late stage of Baker Hughes’ performance of a purchase order, the termination fee payable in respect of that purchase order would approach, but would not exceed, the contract price for that purchase order.

In addition, 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. We exercised such right for the Calcasieu Project and signed such a long-term service agreement with Baker Hughes in December 2022. Moreover, pursuant to the form long-term service agreement and the Calcasieu Project’s long-term service agreement, Baker Hughes is required to provide a long-term availability guarantee whereby Baker Hughes guarantees that the equipment it supplies will reach a minimum annual operating availability. If the equipment Baker Hughes supplies is unable to reach the specified operating availability, liquidated damages will be payable by Baker Hughes. To the extent the liquefaction system reaches an operating availability in excess of a certain level, we would be obligated under any such long-term service agreement to pay Baker Hughes a bonus based upon the amount of such excess. Both Baker Hughes’s and our respective obligations under this long-term service agreement would be subject to certain agreed limitations on liability.

EPC Contracts

Our project companies directly negotiate and contract with, as well as oversee and manage, our equipment vendors for the delivery of the majority of the critical facilities and modules related to LNG production. While we also typically engage an EPC contractor, such EPC contractors increasingly have a limited work scope, far less than for traditional facilities.

We constructed the Calcasieu Project pursuant to an EPC contract and have certified that it was performed in February 2023, subject to customary warranty obligations. In addition, we have entered into EPC contracts for both phases of the Plaquemines Project and for Phase 1 of the CP2 Project that require that the applicable contractor integrate such equipment and facilities and guarantee the full operation of the LNG export facilities. The services under the EPC contracts include contributing to the (i) design of balance of the plant and all interconnections including piping, utilities and associated infrastructure, (ii) procurement of all items not covered by our other construction and supply agreements, (iii) scheduling and coordination of the work and services performed by certain subcontractors and other contractors, (iv) site preparation, (v) installation and connection of all equipment supplied by our equipment suppliers, (vi) construction of the power plant forming part of the project, (vii) compliance with the contractor’s warranty obligations and all applicable laws, codes and standards, and (viii) provision of project controls and construction performance indicators and invoice reconciliation.

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Under each such contract that we have entered into for our projects, the EPC contractor has an uncapped make-good obligation to deliver a facility capable of passing certain performance tests. Each contractor is also required to pay us liquidated damages, subject to a specified cap and sub-limits for certain milestones, for any construction and/or performance testing delay. The aggregate amount of liquidated damages that would be payable under this arrangement with respect to each of these projects, in addition to the liquidated damages that would be payable under certain performance guarantees under the applicable liquefaction and power equipment purchase orders entered into pursuant to the Baker Hughes Master Agreement, are expected to be up to 10% of the aggregate construction cost for each project.

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

For Phase 2 of the CP2 Project and our other development projects, we aim to negotiate and enter into EPC contracts on similar terms as described above. However, as compared to the Calcasieu Project, the Plaquemines Project and Phase 1 of the CP2 Project, we aim to manage additional scopes of work directly. Specifically, we anticipate that we will perform additional EPCM activities and deploy labor that we recruit to leverage lessons learned and the relationships fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project, which we believe will help improve construction efficiency and reduce total costs for such projects. The EPC contracts we have used for the Calcasieu Project, the Plaquemines Project and Phase 1 of the CP2 Project are narrower in scope than the industry standard lump-sum-turnkey EPC agreements used by some of our U.S. Gulf Coast competitors. We expect that the EPC contracts that we use in the future will be even narrower.

We believe the narrowed scopes of our EPC contracts provide certain advantages compared to the standard lump-sum turnkey or “wrap” structure. We believe that, counterintuitively, these traditional lump sum, turn-key, “fixed price” forms of EPC construction can often result in significant delays and change order-driven cost overruns that we are better able to mitigate through our owner-led approach. In addition to incorporating our owner-furnished equipment, we believe our contracts afford us far greater control, execution flexibility, and oversight of the construction process. Where we see opportunities to accelerate procurement and construction or mitigate risk, we have been able to procure equipment and commodities on an accelerated timeline and secure experienced incremental contractors with significant labor resources to supplement EPC efforts and address construction timeline risks.

In addition, we have built an internal EPCM capability, securing a team of experienced leaders and professionals from the EPC industry, primarily with prior relevant experience constructing the Calcasieu Project and the Plaquemines Project facilities. We believe this organization augments the skills and capabilities of our partner EPC contractors and enables proactive leadership and engagement that speeds construction, manages supply chain and project controls, exercises budget adherence and reduces overall project risk. As described above, we anticipate that we will seek to leverage such internal EPCM capabilities to manage additional scopes of work directly for our development projects to reduce cost and accelerate schedule.

Below is a summary of the Plaquemines EPC Contracts and the CP2 Phase 1 EPC Contract.

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Plaquemines EPC Contracts

The Plaquemines EPC Contracts are separate contracts for Phase 1 and Phase 2 of the Plaquemines Project under which KZJV is the EPC contractor and which reflects the terms described above.

Under the Plaquemines EPC Contracts, KZJV will be paid a reimbursable sum for its scope of work, where we will reimburse KZJV for all reimbursable costs incurred in connection with the relevant work (such as costs for materials, transportation and equipment), plus a margin to cover overhead costs and expenses as well as an agreed profit margin. However, all other costs will not be reimbursed and will be borne by KZJV. The estimated reimbursable sum represents the “target price” for each phase of the Plaquemines Project, which is reflected in our estimated total cost for the Plaquemines Project. The target price is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by KZJV or the project schedule.

The Plaquemines EPC Contracts establish an agreed project schedule for the applicable phase, including substantial completion deadlines and final completion deadlines, based on the achievement of the contractual conditions regarding the commissioning and completion of the LNG production systems that comprise Phases 1 and 2 of the Plaquemines Project, which may only be adjusted by change orders as provided in the Plaquemines EPC Contracts. Each of the project schedule milestones requires that the work performed meets or exceeds requirements under the Plaquemines EPC Contracts and certain material project schedule milestones additionally require that the work performed passes performance tests. KZJV has significant milestone and schedule-driven bonus incentives under the Plaquemines EPC Contracts that are intended to promote schedule adherence and a completion mindset. If KZJV fails to successfully pass the performance tests by the applicable deadlines for these milestones for reasons not caused by us or our other contractors, KZJV is obligated to perform all work necessary to successfully pass such tests at its own expense. Additionally, if KZJV exceeds the target price by certain agreed amounts, we could reduce KZJV’s profit margin according to certain predetermined thresholds and if KZJV incurs delays in the project schedule beyond certain deadlines, KZJV could potentially owe us liquidated damages (subject to specified caps). Conversely, if KZJV’s reimbursable costs are below the applicable target price or if KZJV completes certain work ahead of the applicable target schedule, (i) KZJV will be entitled to a share in certain benefits of cost savings and (ii) KZJV will receive incentive payments for early completion of certain milestones.

CP2 Phase 1 EPC Contract

Worley is the contractor under the CP2 Phase 1 EPC Contract. The CP2 Phase 1 EPC Contract is comparable in scope and terms to the Plaquemines EPC Contracts, with certain adjustments to account for the CP2 Project’s schedule and minor configuration differences. The CP2 Phase 1 EPC Contract also includes substantial completion deadlines and final completion deadlines, with associated bonus incentives and exposure to liquidated damages depending on adherence to the project’s schedule.

Like the Plaquemines EPC Contracts, under the CP2 Phase 1 EPC Contract, Worley will be paid a reimbursable sum for its scope of work under similar terms to those included in the Plaquemines EPC Contracts. However, we anticipate that we will seek to manage additional scopes of work directly acting as EPCM, based on lessons learned and the relationships we have fostered with construction and fabrication subcontractors while developing the Calcasieu Project and the Plaquemines Project. The target price under the CP2 Phase 1 EPC Contract is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by Worley or the project schedule.

Carbon Capture and Sequestration Initiative

In May 2021, we announced plans for carbon capture and sequestration, or CCS, facilities at or near the Calcasieu Project and Plaquemines Project sites that will be designed to compress CO2 emissions from these projects and subsequently inject it into subsurface saline aquifers near the project sites, where it would be

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permanently stored. We plan to implement or utilize such CCS facilities at our other projects as well, such as the CP2 Project, the CP3 Project and the Delta Project, which are located nearby the Calcasieu Project and Plaquemines Project. We have conducted extensive studies to confirm the feasibility of the CCS facilities, have leased approximately 27,000 acres of pore space with the State of Louisiana, and are in the process of completing the remaining applications for regulatory approval. We believe we are one of the first movers in the deployment of this technology at scale and are working closely with regulators to become among the earliest commercial scale implementers of CCS capabilities.

Job Creation and Commitment to Local Labor and Community Stewardship

We aspire to set the standard for our industry in achieving positive impacts for our local communities and on a national level.

In connection with the development of our projects, we provide substantial direct and indirect employment opportunities and have been a significant contributor to the domestic labor market with the jobs that we have created and supported. As of , 2024, the Calcasieu Project, the Plaquemines Project and the CP2 Project have been supported by over indirect subcontractor, part-time and full-time jobs. At peak, we estimate that we have supported the employment of up to 9,000 construction jobs to construct the Calcasieu Project and Plaquemines Project. We expect to directly hire approximately 700 permanent employees to operate and manage such projects and have already filled substantially all of these positions.

We strive to hire in-state and local workers where possible and over 90% of the current direct employees at the Calcasieu Project and Plaquemines Project are from Louisiana. We anticipate that the CP2 Project will support the employment of over 7,500 on-site construction jobs at its peak and we expect to hire over 400 workers in permanent operational positions.

Further, we engage with the communities near our project sites by providing full-time employment and educational opportunities that allow local residents to develop new technical skills and succeed in related careers. We primarily pursue this through our “Will to Skill” program and our apprenticeship program. In 2020, we established our educational “Will to Skill” program in partnership with local colleges to provide technical training certifications to residents of the communities near our projects. As of , 2024, over individuals have graduated in the aggregate from the cohorts of the Will to Skill program that we have offered in the various communities located near our project sites. Will to Skill participants will graduate with occupational and industrial certifications that include construction, electrical, welding, maritime, and trucking skills. Recently, in October 2023, we established a new apprenticeship program to provide a 12-month training program to local residents near Lake Charles. Upon the successful completion of the program, individuals are eligible to transition to full time VG employees as field operators and maintenance technicians.

We are a major financial supporter of the local communities in which we operate and have undertaken a multitude of community development and engagement activities. In particular, over the lifecycle of the Calcasieu Project, Plaquemines Project, and CP2 Project, we expect Venture Global will pay more than $6 billion in total Parish property taxes. Regarding outreach and engagement, we have established community advisory groups in each of the parishes where our projects are located. Such community advisory groups include local business owners, community leaders, and residents to meet quarterly and discuss how we can best contribute to the success of the nearby population. We have also instituted certain advancement and donation campaigns to assist with emergency response efforts and community health and safety initiatives with local sheriff officers and fire departments. Also, in Cameron Parish, where our Calcasieu Project and CP2 Project are located, we have developed a public recreation complex and food bank to serve the community and provide additional employment opportunities.

Human Capital Resources

Our human capital is our most valuable asset, and we place a high premium on attracting, developing and retaining talented and high performing employees. As of , 2024, we had over full-time

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employees working on our engineering, project development, project financing, corporate finance, legal and LNG marketing teams. As we develop and construct our projects, we expect to create additional highly skilled engineering, construction, manufacturing and operating full-time and contractor jobs in Louisiana, Texas and Virginia. We offer our employees a wide array of company-paid benefits and performance incentives, which we believe are competitive relative to others in our industry. Our employees are not represented by a labor union or covered by a collective bargaining agreement. We believe our relationship with our employees to be good.

Health and Safety

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

Governmental Regulation

Our operations are subject to extensive federal, state, and local regulation. Applicable laws require us to consult with applicable federal and state agencies, obtain and maintain applicable permits and authorizations, and comply with various ongoing regulatory requirements. This regulatory burden increases the cost of constructing and operating our projects, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. See “Risk Factors—Risk Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports” for more information.

Federal Energy Regulatory Commission (FERC)

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

Under section 3 of the Natural Gas Act, or the NGA, any person proposing to site, construct, or operate facilities (including LNG terminals) to be used for the export of natural gas from the United States to a foreign country must obtain authorization from FERC. FERC exercises comprehensive regulation of interstate natural gas pipelines, including requiring a certificate of public convenience and necessity under NGA section 7 to construct and operate such a pipeline, and requiring that the rates and terms of service for pipeline transportation service be just and reasonable under NGA sections 4 and 5.

In addition to the initial FERC process for each of our projects summarized below, we note that throughout the life of each project, our LNG and pipeline facilities will be subject to ongoing FERC regulation and reporting requirements (as well as those of various other federal, state and local regulatory agencies). FERC’s jurisdiction under the NGA and NGPA allows it to impose civil and criminal penalties for any violations of the NGA or NGPA, and any rules, regulations or orders of FERC up to approximately $1.55 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

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Calcasieu Project

On September 4, 2015, we filed an application with FERC for authorization to site, construct and operate the Calcasieu Project. On February 21, 2019, FERC authorized the Calcasieu Project, as well as the construction and operation of the TransCameron pipeline, subject to numerous conditions, or the Calcasieu FERC Order. No requests for rehearing (or appeal) of the Calcasieu FERC Order were filed.

Construction and commissioning of the Calcasieu Project is subject to ongoing oversight by FERC and the Calcasieu FERC Order imposes ongoing conditions with which we must comply. Since issuance of the Calcasieu FERC Order, we have submitted to FERC over 120 “implementation plan” filings demonstrating compliance with the Calcasieu FERC Order’s conditions and requesting notices to proceed with various scopes of work on the Calcasieu Project, as well as over 80 “commissioning” filings related to various facilities. On February 11, 2022, FERC authorized the export of our first LNG cargo, and we loaded our first commissioning cargo on March 1, 2022. Although we have completed most of the construction of Calcasieu Project, the commissioning phase remains ongoing. As described in detail above in the “—Overview—Our Projects” section, on March 28, 2023, we submitted to FERC an update regarding commissioning and certain reliability challenges and needed repairs and replacements, which have contributed to a delay in commercial operations. FERC authorized our plans for the HRSG remediation on October 12, 2023, and continues to oversee the remediation work. On October 26, 2023, FERC authorized placing the last of our liquefaction blocks in-service while other facilities remain in the commissioning process. We expect to commence commercial operations in late 2024. In February 2024, FERC performed a construction and commissioning inspection, which included a review of the HRSG repair work. FERC noted that the various rectification and remediation work remains ongoing and found that Venture Global “was approaching the diagnosis and remediation of the equipment performance in a careful, technically sound manner” to correctly identify the unexpected equipment performance issues and establish a permanent solution. In its inspection report, FERC also concluded that construction and commissioning activities observed during its inspection were in compliance with the designs and plans filed with and approved by FERC. In May and July 2024, FERC performed subsequent construction and commissioning inspections and each time reached the same conclusions, while noting that additional progress had been made since FERC’s prior inspection and that it will continue to monitor progress.

On March 31, 2021, we requested authorization from FERC to place the TransCameron pipeline in-service, explaining that the TransCameron pipeline is mechanically complete and ready to commence service. FERC granted that request on April 7, 2021. The TransCameron pipeline was placed in service by FERC on April 20, 2021.

On December 3, 2021, we submitted an application with FERC to amend the terms of our FERC authorizations for the Calcasieu Project to increase the permitted capacity under optimal conditions from 12.0 to 12.4 mtpa. This “uprate” in the regulatorily authorized production capacity is based on updated engineering and vendor data, and does not involve the construction of any new facilities nor any modification of the previously authorized facilities. FERC approved that amendment and increased the authorized export capacity to 12.4 mtpa, subject to certain conditions, in an order issued on September 22, 2023.

On February 15, 2024, we submitted to FERC a request for a one-year extension of time, if deemed necessary, to the in-service condition in the Calcasieu FERC Order. Various parties filed objections to the request for extension of time, while generally contending that it is not necessary. FERC issued an order on June 10, 2024 establishing a procedure for it to receive additional comments from intervenors with respect to the request, following which FERC will issue an order on our request for an extension of time. The intervenors have filed supplemental comments and we have responded to them.

Plaquemines Project

On February 28, 2017, we filed an application with FERC for authorization to site, construct and operate the Plaquemines Project. On September 30, 2019, FERC authorized the Plaquemines Project, as well as the

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construction and operation of the Gator Express pipeline, subject to numerous conditions, or the Plaquemines FERC Order. No requests for rehearing (or appeal) of the Plaquemines FERC Order were filed.

Construction of the Plaquemines Project is subject to ongoing oversight by FERC and the Plaquemines FERC Order imposes ongoing conditions with which we must comply. Since issuance of the Plaquemines FERC Order, we have submitted to FERC, as part of a continuing process, more than 137 “implementation plan” filings demonstrating compliance with the Plaquemines FERC Order’s conditions and requesting notices to proceed with various scopes of work on the Plaquemines Project, as well as our initial “commissioning” filings. We are proceeding with construction as the work is authorized by FERC. Notably, in recent months FERC has authorized a series of steps needed to set the stage for commencing liquefaction and our first exports, including introducing natural gas into the terminal and into the gas turbines, commissioning the mooring system and ship to shore links, and commissioning the first liquefaction train with nitrogen. The construction of the related Gator Express pipeline is also subject to oversight by FERC; the pipeline achieved mechanical completion in October 2023. With the requisite FERC authorization, we placed one of the two Gator Express lateral pipelines in-service, which we did on May 16, 2024, and expect to place the remaining Gator Express facilities in place in 2024.

On March 11, 2022, we submitted an application with FERC to amend the terms of our FERC authorization to increase the authorized permitted production capacity under optimal conditions from 24.0 to 27.2 mtpa. This “uprate” in the regulatorily authorized production capacity is based on updated engineering and vendor data, and does not involve the construction of any new facilities nor any modification of the previously authorized facilities. FERC has not yet issued an order regarding this uprate amendment application, though it did issue the environmental assessment regarding it on January 6, 2023, concluding that approval of the amendment would not constitute a federal action significantly affecting the quality of the human environment. On June 21, 2024, PHMSA issued its Letter of Determination and concluded that the uprate project and related design modifications comply with the applicable siting requirements. We expect FERC to approve the amendment now that PHMSA has completed its siting review.

CP2 Project

On December 2, 2021, we filed an application with FERC for authorization to site, construct and operate the CP2 Project, seeking a permitted production capacity of 28.0 mtpa, as well as the related CP Express pipeline. On June 27, 2024, FERC authorized the CP2 Project, as well as the construction and operation of the CP Express pipeline, subject to numerous conditions, or the CP2 Project FERC Order. In July 2024, a group of opponents composed mostly of environmental groups filed a request for rehearing of the FERC authorization, raising a number of challenges to the FERC authorization. In a notice issued in August 2024, FERC denied rehearing by operation of law while providing for further consideration, and it is likely to issue a substantive order on rehearing in the coming months. Project opponents consisting of numerous environmentalist organizations and certain individuals filed petitions for review of FERC’s authorization order with the US Court of Appeals for the D.C. Circuit on September 4, 2024. Construction of the CP2 Project will be subject to ongoing oversight by FERC in accordance with the terms and conditions of the CP2 Project FERC Order, and we have already begun to submit implementation plans for this purpose.

CP3 Project and Delta Project

As of , 2024, we submitted a pre-filing to FERC for the CP3 Project. As of , 2024, the Delta Project remains in the FERC “pre-filing process.” We have not yet submitted a formal FERC application for the CP3 Project or the Delta Project. Such approvals are subject to a number of risks, and there can be no assurances as to when we will file the formal applications or when we will receive the approvals, if at all. For more information on these risks, see “Risk Factors—Risk Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

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DOE Export Authorizations

Section 3 of the NGA requires any person seeking to import natural gas from, or export natural gas to, a foreign country to obtain authorization from the DOE. The DOE’s Office of Fossil Energy and Carbon Management, or DOE/FECM, reviews applications to import or export natural gas.

The NGA sets forth separate standards of review for exports to (1) countries with which the United States has a free trade agreement requiring national treatment for trade in natural gas, or FTA Nations, and (2) countries with which there is no such free trade agreement in effect, or Non-FTA Nations. Applications seeking authorization to export LNG to FTA Nations are deemed consistent with the public interest and must be granted without modification or delay. FTA Nations currently include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. In contrast, Non-FTA Nations export applications are subject to a public interest review. DOE/FECM will grant the requested authorization unless it finds, after providing for a public comment period, that the proposed exports will be inconsistent with the public interest, and may approve an application in whole or in part, and with such modifications and upon such terms and conditions as it deems necessary or appropriate. DOE/FECM’s established practice is to act on long-term authorizations to export to Non-FTA Nations only after the FERC has authorized the siting, construction and operation of the associated LNG facilities.

In January 2024, the Biden administration announced a temporary pause on new authorizations of natural gas exports to non-FTA Nations while the DOE conducts studies to update its analyses regarding whether the exports are “not inconsistent with the public interest” to consider the latest available information regarding macro-economic impacts, domestic energy prices, potential greenhouse gas or climate or other environmental effects, and national security implications. We expect that this decision and the development of the studies will impact all of our pending applications for exports to Non-FTA Nations described below. DOE officials have publicly indicated that they expect the updated studies, including a public comment period, to be finalized around the first quarter of 2025. Accordingly, a change in administration resulting from the presidential election in November 2024 may impact the DOE’s final decision. On July 1, 2024, a Federal District Judge in Louisiana granted a motion for preliminary injunction by numerous states, holding the DOE pause appears to be unlawful and staying the pause in its entirety. The DOE has appealed that decision. Furthermore, there can be no assurance as to how or when the DOE will now proceed, the final resolution of the legal challenges, the outcome of the DOE’s updates to its analyses and procedures, or the impact on our existing and future projects, including our related contracts. On August 31, 2024, DOE issued a non-FTA export authorization for one project (NFE Altamira FLNG, a 1.4 mtpa project) but limited its term to 5-years, ruling that a more complete record is needed to evaluate a longer term. Attention to DOE’s approach to export authorizations has also resulted in legislative efforts intended to facilitate LNG exports. For instance, in July 2024, Senators Manchin and Barrasso, the Chairman and Ranking Member of the Senate Energy and Natural Resources Committee, respectively, released bipartisan legislation intended to strengthen American energy security by accelerating permitting processes that would, among other things, require DOE to approve or deny all pending and future applications to export LNG to non-FTA nations within 90 days after publication of the related final NEPA document. For more information on these risks, see “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

Calcasieu Project

DOE/FECM approved our applications for exports from the Calcasieu Project to FTA Nations in May 2013 for 5 mtpa, in May 2014 for an additional 5 mtpa, and in February 2015 for an additional 2 mtpa. Thus, DOE/FECM granted our long-term export authorizations to FTA Nations in three separate orders, for a total volume of 620 Bcf/yr of natural gas (equivalent to 12 mtpa), and originally for a term of 25 years beginning the earlier of

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(i) the date of first export or (ii) seven or eight years (depending on the specific terms of each authorization) from the date of the authorization. DOE/FECM granted us long-term authorization for export to Non-FTA Nations on March 5, 2019. The Non-FTA export authorization also is for up to 620 Bcf/yr of natural gas (equivalent to 12 mtpa), and originally was for a term of 20 years from the date of first export, while providing that exports must commence no later than seven years from the date of the authorization. The authorized volumes to FTA Nations and Non-FTA Nations are not cumulative.

On August 12, 2020, we submitted to DOE/FECM an application requesting extension of the term in all the Calcasieu Project’s long-term export authorizations, pursuant to DOE/FECM’s final policy statement issued on July 29, 2020, entitled “Extending Natural Gas Export Authorizations to Non-Free Trade Agreement Countries Through the Year 2050.” On October 21, 2020, DOE/FECM granted that request, extending the term in each Calcasieu Project export authorization through December 31, 2050 (inclusive of any make-up period).

On December 18, 2020, DOE/FECM issued a blanket order, Order No. 4641, amending certain existing export authorizations, and amended the existing long-term authorizations for the Calcasieu Project to include short-term export authority, including to export commissioning volumes.

In accordance with the terms of our DOE export authorizations, we notified DOE of the export of our first export cargo from the Calcasieu Project on March 22, 2022. Subsequently, we have submitted monthly reports to DOE providing details regarding all our exports. We are also subject to various other reporting requirements regarding the Calcasieu Project under the terms of our export authorizations, including semi-annual status reports and the obligation to submit to DOE copies of all long-term LNG offtake and natural gas contracts. We have complied with these reporting requirements.

On December 3, 2021, we submitted an application with DOE/FECM to amend the terms of our FTA and non-FTA export authorizations for the Calcasieu Project to increase the authorized export capacity from 12.0 to 12.4 mtpa. As explained with regard to the related FERC application, this “uprate” in the regulatorily authorized production capacity is based on updated engineering and vendor data, and does not involve the construction of any new facilities nor any modification of the previously authorized facilities. DOE authorized the increased level of export to FTA Nations on April 22, 2022, but has not yet acted on the request to increase the authorized level of exports to Non-FTA Nations. Following the Biden administration’s announcement in January 2024, we expect that the DOE’s decision likely will be delayed until there is a change in administration and/or the DOE completes its studies to update its consideration of issues affecting the public interest implications of LNG exports. See “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

Plaquemines Project

DOE/FECM approved on July 21, 2016, our application for exports from the Plaquemines Project to FTA Nations for 1,240 Bcf/yr of natural gas (equivalent to 24 mtpa), and originally for a term of 25 years beginning the earlier of (i) the date of first export or (ii) seven years from the date of the authorization. DOE/FECM granted us long-term authorization for export from the Plaquemines Project to Non-FTA Nations on October 16, 2019. The Non-FTA export authorization also is for up to 1,240 Bcf/yr of natural gas (equivalent to 24 mtpa), and originally was for a term of 20 years from the date of first export, while providing that exports must commence no later than seven years from the date of the authorization. The authorized volumes to FTA Nations and Non-FTA Nations are not cumulative.

On August 12, 2020, we submitted to DOE/FECM an application requesting extension of the term of the Plaquemines Project’s long-term export authorizations, pursuant to DOE/FECM’s final policy statement issued on July 29, 2020, entitled “Extending Natural Gas Export Authorizations to Non-Free Trade Agreement

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Countries Through the Year 2050.” On October 21, 2020, DOE/FECM granted that request, extending the term in each Plaquemines Project export authorization through December 31, 2050 (inclusive of any make-up period).

Just as for the Calcasieu Project, the blanket order described above also amended the existing long-term authorizations for the Plaquemines Project to include short-term export authority, including to export commissioning volumes.

We are subject to various reporting requirements regarding the Plaquemines Project under the terms of our export authorizations, including semi-annual status reports and the obligation to submit to DOE copies of all long-term LNG offtake and natural gas contracts. We have complied with these reporting requirements. Additional DOE reporting will be required once LNG exports commence.

On March 11, 2022, we submitted an application with DOE/FECM to amend the terms of our FTA and Non-FTA export authorizations for the Plaquemines Project to increase the authorized export capacity under optimal conditions from 24.0 to 27.2 mtpa. As explained with regard to the related FERC application, this “uprate” in the regulatorily authorized production capacity is based on updated engineering and vendor data, and does not involve the construction of any new facilities nor any modification of the previously authorized facilities. DOE authorized the increased level of export to FTA Nations on June 13, 2022, but has not yet acted on the request to increase the authorized level of exports to Non-FTA Nations, which is consistent with DOE practice of waiting to take action on the non-FTA portion of an application until after FERC has approved the corresponding project. Following the Biden administration’s announcement in January 2024, we expect that the DOE’s decision likely will be delayed until there is a change in administration and/or the DOE completes its studies to update its consideration of issues affecting the public interest implications of LNG exports. See “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.”

In June 2024, the DOE authorized the Plaquemines Project to import LNG from various sources in total volumes up to the equivalent of 6 Bcf of natural gas, and authorized it to re-export the same quantity of previously imported LNG in July 2024. The Plaquemines Project will utilize these blanket authorizations to cool-down its cryogenic facilities as part of the start-up of Phase 1 of the Plaquemines Project.

CP2 Project

DOE/FECM approved on April 22, 2022, our application for exports from the CP2 Project to FTA Nations for a 1,446 Bcf/yr of natural gas (equivalent to 28 mtpa), for a term extending through 2050. Our request for authorization for exports from the CP2 Project to Non-FTA Nations remains pending before DOE/FECM. Following the Biden administration’s announcement in January 2024, we expect that the DOE’s decision likely will be delayed until there is a change in administration and/or the DOE completes its studies to update its consideration of issues affecting the public interest implications of LNG exports. See “Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects, including as a result of DOE’s ongoing studies to update its consideration of issues affecting the public interest implications of LNG exports.” We are subject to various other reporting requirements regarding the CP2 Project under the terms of our FTA export authorization, including semi-annual status reports and the obligation to submit to DOE copies of all long-term LNG offtake and natural gas contracts. We have complied with these reporting requirements.

CP3 Project and Delta Project

We have not yet filed any application with DOE/FECM for the authorization of natural gas exports from the CP3 Project or the Delta Project. We anticipate submitting the export authorization application for the CP3 Project and the Delta Project at approximately the same time as our formal FERC applications for each project.

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Department of Transportation Pipeline and Hazardous Materials Safety Administration

Our projects must comply with certain safety standards set by PHMSA. 49 C.F.R. Part 193, Federal Safety Standards for Liquefied Natural Gas Facilities, which establishes minimum federal safety standards for the siting, construction, operation, and maintenance of onshore LNG facilities and the siting of marine cargo transfer systems at waterfront LNG plants. These standards also incorporate by reference the National Fire Protection Association, Standard 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas.” Although PHMSA does not issue a permit in connection with LNG facilities, it participates as a cooperating agency during FERC’s review of a project to evaluate whether the proposed design meets DOT requirements. PHMSA issued a Letter of Determination, or LOD, regarding compliance with the applicable standards for each of the Calcasieu Project (including its “uprate” amendment) and the Plaquemines Project as part of the FERC process, before each project was authorized by FERC. PHMSA has also issued its LOD for the CP2 Project, as well as for the Plaquemines Project “uprate.” Once constructed and operational, each of our LNG facilities’ compliance with 49 C.F.R. Part 193 will be subject to DOT’s inspection and enforcement program.

Other Governmental Permits, Approvals and Authorizations

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

Commodity Futures Trading Commission

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

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

“Swap Dealers” and “Major Swap Participants” must register with the CFTC and comply with heightened business conduct, reporting/recordkeeping, margin, and other requirements in connection with their swaps activities. Based on the level and nature of our swap activities (which are to hedge and mitigate commercial risk), we do not expect to fall within the CFTC’s definition of Swap Dealer or Major Swap Participant.

The CFTC has also made mandatory clearing determinations with respect to certain categories of swaps. The CFTC currently requires mandatory clearing of certain classes of interest rates and index credit default swaps, and may expand this requirement to additional categories of swaps in the future. Swaps subject to mandatory clearing must be submitted to a derivatives clearing organization, or DCO, for clearing, and in some cases, must be executed on an exchange or swap execution facility. Mandatory clearing and trade execution increase the transaction costs associated with swaps. However, the CEA provides an exception to the mandatory clearing and trade execution requirements for commercial end-users, or the end-user exception, provided the

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end-user is (i) not a “financial entity” as defined in the CEA; (ii) is using the swap to hedge or mitigate commercial risk; and (iii) complies with certain reporting and board approval requirements in connection with its election of the end-user exception, as applicable. We currently qualify for and rely on the end-user exception from the mandatory clearing and trade execution requirements in connection with our swaps activities; however, should we fail to qualify for the exception, we may be subject to DCO margin requirements, thereby increasing our swaps transaction costs.

Swaps that are not submitted to a DCO for clearing are subject to initial and variation margin requirements if the swap is between a Covered Swap Entity (i.e., a Swap Dealer or Major Swap Participant) and a “financial end user,” but these margin requirements do not apply to our uncleared swaps if we do not qualify as a financial end user.

In addition, 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.

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

Environmental Regulation

Our projects are subject to various federal, state, and local environmental statutes and regulations intended to ensure the protection of the environment. In certain cases, these environmental laws and regulations require us to obtain permits and authorizations and engage in agency consultations prior to construction and operation of a project. Many laws and regulations restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. See “Risk Factors—Risks Relating to Regulation and Litigation—Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating and/or construction costs and restrictions” for more information.

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

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

Clean Air Act (CAA)

Our projects are subject to the CAA and comparable state and local laws. Under the CAA, the EPA has the authority to control air pollution by issuing and enforcing regulations for entities that emit substances into the air. The EPA has promulgated regulations for major sources of air pollution and has delegated implementation of

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these regulations to state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality. In addition to having obtained relevant air permits from the Louisiana Department of Environmental Quality prior to construction of the Calcasieu Project and the Plaquemines Project, we are subject to ongoing emissions standards, requirements, and reporting obligations. The EPA’s New Source Performance Standards regulate emission rates and impose emission limits and monitoring, reporting and record keeping requirements. The EPA has also issued a Mandatory Greenhouse Gas Reporting Rule, which requires petroleum and natural gas systems that emit 25,000 metric tons or more of CO₂ a year to annually report GHG emissions to the EPA. Equipment subject to reporting under this rule includes LNG storage, regasification, and liquefaction equipment. We must also comply with Louisiana state air quality regulations and standards, codified in Louisiana Administrative Code Title 33, Part III. With respect to the CP2 Project, as a result of pipeline operations in Jasper County, Texas and Newton County, Texas, we will also be subject to the regulatory authority of the Texas Commission on Environmental Quality.

Coastal Zone Management Act (CZMA)

The Coastal Zone Management Act, or CZMA, is intended to ensure the effective management, beneficial use, protection, and development of the nation’s coastal zone. Under the CZMA, participating states are required to develop management programs demonstrating how they will meet their obligations and responsibilities in managing their coastal areas. The Louisiana Department of Natural Resources, which administers the CZMA for each of our projects, issued a coastal use permit and related mitigation plan for the Calcasieu Project and an exemption for the LNG terminal and a “no direct or significant impact” (NDSI) exemption for the marine facility for the Plaquemines Project. The CP2 Project received its CZMA authorization in March 2024.

Clean Water Act (CWA) and Rivers and Harbors Act

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

Resource Conservation and Recovery Act (RCRA)

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

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

Section 7 of the Endangered Species Act provides that any project authorized by any federal agency should not jeopardize the continued existence of any endangered species or threatened species, or result in the

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destruction or adverse modification of habitat of such species which is determined to be critical. The Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, establishes procedures designed to identify, conserve, and enhance essential fish habitat for those species regulated under a federal fisheries management plan. During the FERC review process for each of our Projects, we engaged in consultation with the relevant federal agencies pursuant to the ESA and MSFCMA.

Such consultation was completed for the Calcasieu Project, the Plaquemines Project and the CP2 Project.

The CP3 Project and the Delta Project have not received their Section 7 clearance as of , 2024.

The issuance of requisite permits and authorizations for our projects may be subject to environmental review under the National Environmental Protection Act, or NEPA. NEPA requires federal agencies to evaluate the environmental impact of major agency actions that may significantly affect the quality of the human environment, such as the granting of a permit or similar authorization for the development of certain projects. As part of NEPA review, federal agencies will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. In January 2023, the Council on Environmental Quality, or CEQ, issued interim guidance to assist agencies in analyzing GHG emissions and climate change effects under NEPA. Additionally, in September 2023, the White House directed agencies to consider the social cost of GHG emissions when conducting environmental reviews pursuant to NEPA, and in May 2024, CEQ published its final “Phase 2” NEPA regulations, which include specific direction to account for both climate change and environmental justice effects in NEPA reviews. The NEPA review process can lead to significant delays in approval of such projects and the issuance of the requisite permits. As a result of its NEPA review, a federal agency may decide to deny permits or other support for a project, or condition approvals on certain modifications or mitigation actions.

Seasonality

Seasonal weather can affect the need for our LNG sales. While we expect that a substantial amount of our LNG will be sold under long-term, post-COD SPAs, due to the commissioning activities at the Calcasieu Project, including the marketing, loading and shipping of our cargos of LNG, we have already begun experiencing, and we expect to experience for our other projects as we begin commissioning activities for such projects, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets. Additionally, excess LNG produced by our projects above the nameplate capacity that is sold by VG Commodities or otherwise can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium- or long-term contracts, including on a forward spot basis, which would expose our revenues to such volatility and fluctuation in seasonal demand. Changes in temperature and weather may affect both power demand and power generation mix in the locations we service, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar or wind, thus affecting the need for regasified LNG. These changes can increase or decrease demand for LNG and accordingly, fluctuations in revenue during quarters of high and low demand, respectively, could have a disproportionate effect on our results of operations, especially with regard to the LNG sold into the spot market. For more information on these risks, see “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, which could, in turn, negatively affect the price of our Class A common stock.”

Competition

The global LNG and natural gas markets are highly competitive. We compete with many participants across an integrated supply chain, including independent LNG producers, commodities marketing and trading firms, national energy companies, utility companies, and major multinational energy companies, primarily over supplies of natural gas and sales of our LNG. Historically, our competitors have developed LNG facilities at a

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scale and complexity that has gradually increased over time. We believe the costs associated with these other projects are further complicated by their bespoke nature, which limits the opportunity for process improvement and operational efficiency gains from one project to the next. In contrast, we utilize a repeatable configuration across the projects that we develop, which enables us to continually refine and optimize our LNG production operations. We believe our proprietary mid-scale, factory-built liquefaction train design, project execution excellence, access to well-priced and abundant, domestically sourced natural gas, simultaneous construction and integrated operations approach, with its associated commissioning cargos and proceeds, capital strength, leadership, and mission and values-led culture position Venture Global well to compete and thrive against this diverse competitive landscape.

Energy Supply & Demand and VG’s Competitive Advantage

LNG is a vital commodity needed across the world to provide reliable, low-cost, low-emission energy. We believe that our differentiated business strategy positions us to serve as a leading, low-cost supplier of this crucial fuel and play a major role in international energy markets.

We believe our liquefaction technology, configuration, and owner-led approach allows us to bring substantial quantities of LNG to the market faster than competing LNG developers. We believe these capabilities, taken together with our pipeline developments, LNG tankers, and regasification assets, will allow us to supply energy to an increasing number of global customers to meet the world’s current and rapidly growing demand.

In the near- and medium-term, energy demand is projected to increase substantially. Such demand growth factors include existing macro-economic trends, such as the expansion of the world’s middle-class population, which will require additional access to energy-dependent consumer staples such as air conditioning, heating, and lighting. Additionally, new sources of significant energy consumption are emerging. For example, data center demand, driven by the burgeoning artificial intelligence industry, will accelerate this global demand story.

Given such robust and sustainable market dynamics, we believe that LNG has the potential to become an increasingly critical commodity to support such sources of demand, which require dispatchable and reliable, 24/7 baseload power. Our business model of developing, building, and delivering low-emission LNG is repeatable, portable – domestically and internationally – and well-positioned to address this growing need. We believe our model can be deployed on an industry-leading schedule to optimize our existing liquefaction projects with “inside-the-fence” expansions, as well as in new greenfield developments.

Simply put, we believe our scalable approach uniquely positions Venture Global to competitively serve the world’s growing energy demand.

Pricing Dynamics

We are subject to market-based price competition, reflecting supply and demand market pricing dynamics, with respect to revenue associated with any sales of our commissioning cargos and sales of LNG in excess of our nameplate capacity. Due to the commissioning activities at the Calcasieu Project, including the marketing, loading and shipping of our cargos of LNG, we have already begun experiencing competition with respect to LNG sales, including the effects of changes in supply and demand due to recent market volatility. The balance between the availability of LNG and the market demand for LNG significantly affects competition and the market price for our products. This dynamic is particularly acute for cargos sold on a forward spot or short-term contracted basis, such as any commissioning and excess capacity cargos.

Even after COD for our projects, we may continue to have a meaningful component of our production and sales subject to spot and short- or intermediate-term market dynamics. This may occur as a result of marketing excess capacity cargos through VG Commodities under excess capacity SPAs to the extent these cargos are not

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previously contracted, or as a result of marketing any portion of the nameplate capacity of our projects that is not contracted under post-COD SPAs at any time. LNG often supports base load power generation and other end uses among LNG offtakers. Accordingly, supplier geographic diversity is an important element of portfolio management for such offtakers. As offtake markets grow, we anticipate that producers based in the United States, such as Venture Global, will maintain or grow market share, with our competitive advantage supplemented by our logistics and delivery capabilities that are enabled by our fleet of LNG tankers. However, increases in the production of LNG by our competitors, could have a material adverse effect on the viability of any of our planned projects and on our ability to compete with them successfully.

Pricing and Contract Terms

Our longer-term post-COD SPAs for each of our projects are relatively more insulated from spot market price volatility than the sales of our commissioning cargos and any sales of LNG in excess of our nameplate capacity, given the contractual protections, price stability and predictability of both gas supply and LNG offtake. After any of our projects, or phase thereof, reaches its respective COD, the project is required to begin to deliver cargos to service its post-COD SPAs then in place for such project or phase. However, our projects may still be subject to market-based spot price competition if we need to replace any existing SPAs, whether due to natural expiration, customer default or otherwise.

The Calcasieu Project and the Plaquemines Project are not currently experiencing competition with respect to long-term LNG sales, given that each of their entire expected nameplate capacity has been contracted under post-COD SPAs. These projects would be subject to the risk of LNG price competition at times when we need to replace any existing post-COD SPAs, whether due to natural expiration, customer default or otherwise, or enter into new SPAs, as well as competition for sales of commissioning cargos. Our current development projects, any future projects we develop and any expansions of our projects will compete with other domestic and international suppliers on the basis of price per contracted volume of LNG with other LNG liquefaction projects throughout the world, including other liquefaction projects being developed by us and other LNG liquefaction projects in operation and under development.

The price of LNG captured by a project can be affected by, among other factors, global supply and demand, historical reputation, geopolitical stability, project location, interest rates, and contract flexibility. For example, increases in the production of LNG by our competitors, or decreases in their LNG prices, could have a material adverse effect on our ability to secure SPAs for our current development projects, any future projects we develop and any expansions of our projects.

Market Access and Participants

As a new market entrant, we compete against other companies with stronger brand recognition and more established relationships with customers. We believe that in a commodities market, lowest risk-adjusted liquefaction cost provides a key, sustainable competitive advantage, particularly for new market entrants. We believe our proprietary configuration, speed of construction and simultaneous construction and commissioning, with related commissioning cargo production, allows us to take a differentiated approach that seeks to reduce costs and compresses the timeline to produce and sell LNG after commencing full construction. Accordingly, we believe our projects are well positioned to compete globally. As demand for LNG, and more broadly, energy security grows, we believe that producers based in the United States, such as ourselves, may have the ability to maintain or grow market share.

In addition, we believe our planned fleet of LNG vessels, and their role in the energy supply chain, along with the regasification capacity we have contracted, enable us to compete against large institutional marketing and trading firms and market and optimize delivered cargos to customers that lack the ability to manage logistics for their own accounts.

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Current and Potential Competitors

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

For additional information about the risks to our business related to competition, see “Risk Factors—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” and “Risk Factors—Risks Relating to the LNG Industry—We face competition based upon the international market price for LNG.”

Insurance

We maintain a comprehensive insurance program to insure potential losses to Venture Global, the Calcasieu Project and the Plaquemines Project from physical loss or damage, including due to floods and named windstorms, as well as third-party liabilities, during construction and subsequent operation. We expect to establish a similar comprehensive insurance program for the CP2 Project, with initial environmental, third party liability and cargo policies in place, and our current development projects at the appropriate and prudent time. In addition, we expect to establish a comprehensive insurance program to insure against customary risks and losses for our LNG tankers and regasification terminal assets at the appropriate and prudent time and have already placed protection and indemnity coverage and hull and machinery insurance for our two, newbuild LNG tankers that were delivered in July 2024 and placed charterers’ liability insurance for our two chartered LNG tankers that were delivered in August and September 2024. We may not be able to maintain adequate insurance in the future at rates that are considered reasonable. See “Risk Factors—Risks Relating to Our Business—We will be 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.”

Construction All-Risk, or CAR, Insurance

We obtained Construction All-Risk insurance policies, or CAR policies, for the Calcasieu Project and the Plaquemines Project, consisting of a very large quota-share and layered property insurance programs written with specialist international insurers that have been placed solely for the construction of the projects. Such CAR insurance policies partially transition to Operating All-Risk (OAR) coverage as certain milestones are achieved and remain effective until the project achieves Facility Substantial Completion under the applicable EPC contracts (which occurred in late 2022 for the Calcasieu Project). Such insurance covers all construction or installation work including, coverage for mechanical and electrical breakdown as well as testing and commissioning required to complete the projects. The CAR policies also include Delay-in-Start-Up (DSU) coverage. This construction insurance has deductibles, waiting periods, sub limits, and aggregate limits that are normal and customary for these types of insurance policies. The CAR policy for the Calcasieu Project is no longer in effect given that the EPC work has been completed. The CAR policy for the Plaquemines Project has a combined limit for CAR and DSU of $2.2 billion with a standard deductible of $1 million per occurrence for property damage and a 60-day waiting period per occurrence for DSU. We expect to enter into similar CAR policies for our current development projects.

Third Party Liability, or TPL, Insurance

VGLNG has TPL insurance with a limit of $11 million. Third party liability risks are covered in the Terminal Operator’s Liability policy for the Calcasieu Project (described below). The Plaquemines Project has a TPL insurance policy which includes a limit of $200 million per occurrence and in the annual aggregate and that

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is subject to various sublimits, terms and conditions. The deductible amount is $1 million for each occurrence. Similarly, the CP2 Project has a TPL insurance policy which includes a limit of $200 million per occurrence and in the annual aggregate and that is subject to various sublimits, terms and conditions. The deductible amount is also $1 million for each occurrence. We expect to enter into a similar TPL policy for our current development projects.

Terminal Operator’s Liability and Operational All-Risk, or OAR, Property Insurance

Once our projects achieve certain completion milestones, their OAR policies come into effect and provide coverage for property and business interruption for such project. We intend to obtain insurance coverage that is in such form and in such amounts as are customary for project facilities of similar type and scale to our projects. For the Calcasieu Project, we maintain the following types of insurance as of , 2024:

•

the Terminal Operator’s Liability Program, which is structured as a primary and layered excess liability insurance program, which provides cover for marine and land based third party liabilities. The Calcasieu Project policy has limits of $500 million per occurrence and in the annual aggregate and the deductible is $100,000 per occurrence;

•

the OAR Insurance, which is a large quota-share and layered property insurance program written with specialist international insurers. The Calcasieu Project cover has a combined limit of $2.4 billion for both physical damage and business interruption, the standard deductible for physical damage losses is $5 million per occurrence and the waiting period for business interruption losses is 60 days per occurrence.

Named Windstorm Insurance (NWS)

The Calcasieu Project and the Plaquemines Project each maintain a Named Windstorm Insurance Program, which is structured as a layered program with a limit of $250 million at each location. This is placed with VGLNG Insurance, LLC, or VGLNG Insurance, one of our subsidiaries. The Calcasieu Project has cover for physical damage and business interruption, while the Plaquemines Project has cover for CAR and DSU. The deductible for CAR/physical damage losses is $50 million per occurrence and the waiting period for DSU/business interruption losses is 60 days per occurrence. Losses in excess of $50 million but less than $100 million are retained solely by VGLNG Insurance. For losses in excess of $100 million but less than $300 million, VGLNG Insurance, LLC is reinsured 100% by reputable third-party insurers.

Total NWS-claims filed for the years ended December 31, 2023, 2022 and 2021 were $0, $0 and $0, respectively. VGLNG Insurance held $ million in cash and cash equivalents at , 2024 from premiums paid by the Calcasieu Project and the Plaquemines Project for the coverage described above. We expect that as we begin commercial operations at our Calcasieu Project, continue construction at the Plaquemines Project, and begin construction of our current development projects, we will continue to pay premiums to VGLNG Insurance to obtain adequate named windstorm risk-coverage for our projects. We anticipate that we will maintain similar policies for the CP2 Project, the CP3 Project and the Delta Project in the future.

Properties

In the aggregate, as of , 2024, we owned, leased or had an option to lease or purchase nearly 6,000 acres of land on the United States Gulf Coast.

For the Calcasieu Project, we entered into ground leases with various landowners in Cameron Parish, Louisiana, for up to 70 years. These ground leases cover approximately 432 acres of land for an initial term of 30 years, with four 10-year extensions exercisable at our option. The Calcasieu Project site also benefits from eight separate material offloading sites that are situated on the east side of the Calcasieu Ship Channel, have access to the primary access road to the project site and are adjacent to the Calcasieu Project and the CP2 Project

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sites. They range from approximately three to ten acres, and we are using these offloading sites to offload equipment and building materials during construction. These offloading sites are held under ground leases by one of our subsidiaries and we have access to these sites under access license agreements with that subsidiary.

We also entered into a 30-year lease with the Plaquemines Port Harbor and Terminal District, covering the 630 acres of land on which the Plaquemines Project is located. This lease may be extended at our option for up to four additional 10-year terms, up to 70 years in the aggregate. We also have lease option agreements to lease up to an additional approximately 1,100 acres of adjacent land for the Delta Project under substantially similar terms as our existing lease for the Plaquemines Project.

We entered into various 30-year leases covering approximately 1,130 acres of land on which the CP2 Project will be located or adjacent to. We acquired fee ownership to approximately 27 acres of the project site in 2023.

We also entered into a 30-year lease covering 840 acres of land for the CP3 Project. This lease may be extended at our option for up to four additional 10-year terms, up to 70 years in the aggregate.

We own the office space in Arlington, VA where our principal executive offices are located. In addition, we lease office space in Houston, TX; Singapore; London, England; and Tokyo, Japan. These office leases expire or become subject to renewal clauses at various dates.

Intellectual Property

We rely on a combination of intellectual property rights, including know-how, trade secrets, license agreements, confidentiality procedures, non-disclosure agreements, and employee non-disclosure to establish, maintain and protect our intellectual property and other proprietary rights. In particular, we license natural gas processing technology from third parties for each of our liquefaction facilities. In addition, under our agreements with Baker Hughes, we own certain know-how and trade secrets relating to aspects of the liquefaction systems, including the routing of the piping and valves within the liquefaction modules and optimization of other module designs, the sharing of supporting equipment between individual liquefaction trains, and the management of mixed refrigerant in the liquefaction process.

However, the efforts we have taken to protect our intellectual property rights may not be sufficient or effective. From time to time, legal action by us may be necessary to enforce or protect our intellectual property rights or to determine the validity and scope of the intellectual property rights of others, and we may also be required from time to time to defend against third-party claims of infringement, misappropriation or other violation. Additionally, although we take reasonable steps to safeguard our trade secrets, trade secrets can be difficult to protect, and others may independently discover our trade secrets and other confidential information. Failure to protect our intellectual property rights or other proprietary rights adequately could significantly harm our competitive position, business, financial condition and results of operations. See “Risk Factors—Risks Relating to Intellectual Property, Data Privacy and Cybersecurity—If we are unable to obtain, maintain, protect and enforce our intellectual property rights, our business may be adversely affected.”

Cybersecurity and Data Privacy

Our projects and any other natural gas liquefaction and export 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 IT systems. These systems may thus be attractive targets for a cyber-attack. 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. We deploy a cybersecurity strategy that is designed to prevent cyber threats as well as recover from cybersecurity incidents with disaster recovery resources. The basis of design for our IT systems are standards that align with existing NERC CIP standards and comply with the most stringent NIST standards for data integrity. In addition to a group of network hygiene operating policies, we

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deploy network and perimeter firewall protections and cloud security packages. We also employ a multi-cloud backup strategy, with backups maintained on cloud platforms that facilitate restoration of plant and business capabilities. Finally, we also keep tape backups, as physical gold copies, that are sent periodically for offline tape storage in a secured storage facility. Regardless, a significant cyber incident involving our IT systems, or those of any of our third party vendors or contractors with which we do business, could negatively impact our operations. See “Risk Factors— Risks Relating to Intellectual Property, Data Privacy and Cybersecurity—Hostile cyber intrusions, or other issues with our information technology, could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have a material adverse effect on our business.”

We are also subject, or may become subject, to increasingly complex and changing laws, directives, industry standards, rules and regulations, as well as contractual obligations, related to data privacy and security in the United States and around the world that impose broad compliance obligations on the collection, transmission, dissemination, use, privacy, confidentiality, security, retention, availability, integrity and other processing of personal information. Any failure or perceived failure by us to comply with any laws, rules or regulations relating to data privacy and security could adversely affect our reputation, results of operations and financial condition. See “Risk Factors— Risks Relating to Intellectual Property, Data Privacy and Cybersecurity—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.”

Legal Proceedings

We are involved, and in the future may become involved, in various claims, lawsuits, and other proceedings incidental to the ordinary course of our business from time to time. For example, we are currently in arbitration proceedings with seven term SPA customers for the Calcasieu Project and with the Calcasieu EPC Contractor. See “Risk Factors—Risks Relating to Regulation and Litigation—We are involved and may in the future become involved in disputes and legal proceedings,” “Risk Factors—Risks Relating to Regulation and Litigation—If we are unsuccessful in our current and any potential future arbitration proceedings with our customers, the amounts that we are required to pay may be substantial and certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project.”

Further, from time to time, we may be a party to various administrative, regulatory or other legal proceedings, such as various proceedings before FERC related to our projects. 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 are required to assess the likelihood of any adverse judgments or outcomes related to these legal contingencies, as well as potential ranges of probable or reasonably possible losses. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The determination of the amount of any losses to be recorded or disclosed as a result of these contingencies is based on a careful analysis of each individual exposure with, in some cases, the assistance of outside legal counsel. There can be no assurance that any accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise. If we are unsuccessful in defending ourselves against certain claims by our post-COD SPA customers for the Calcasieu Project described above, the amounts we 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.

Other than such foregoing claims, as of the date hereof, there are no pending or threatened legal claims or proceedings, individually or in the aggregate, which we believe could have a material adverse effect on our business or financial condition. For more information, see Note 15 – Commitments and Contingencies in our annual financial statements, included elsewhere in this prospectus.

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MANAGEMENT

Board of Directors and Executive Officers

Set forth below is certain biographical and other information regarding our directors and executive officers as of , 2024:


Name	Age	Position
Executive Officers
Michael Sabel		Chief Executive Officer, and Executive Co-Chairman of the Board, and Founder
Robert Pender		Executive Co-Chairman and Executive Co-Chairman of the Board, and Founder
Jonathan Thayer		Chief Financial Officer
Brian Cothran		Chief Operating Officer
Fory Musser		Senior Vice President, Development
Keith Larson		General Counsel and Secretary
Thomas Earl		Chief Commercial Officer
Non-Employee Directors
Sari Granat		Director
Andrew Orekar		Director
Thomas J. Reid		Director
Jimmy Staton		Director
Roderick Christie		Director

Michael Sabel

Michael Sabel is one of the Company’s co-founders. Mr. Sabel has served as the Company’s Chief Executive Officer and as an Executive Co-Chairman of the Company’s board of directors since September 2023. Mr. Sabel has also served as VGLNG’s sole Chief Executive Officer since October 2020 and has served as an Executive Co-Chairman of VGLNG’s board of directors since August 2014. Mr. Sabel was also Co-Managing Partner of Legacy VG Partners since 2012, until Legacy VG Partners merged with the Company, and is currently Co-Managing Partner of VG Partners, the Company’s controlling shareholder. Prior to founding Venture Global, Mr. Sabel spent decades working in the energy, technology and financial service sectors in senior leadership, new company formation, technology licensing and corporate business development. We believe Mr. Sabel is qualified to serve as director due to his experience as one of our co-founders and as our Chief Executive Officer, his decades of experience in capital markets transactions, his comprehensive experience in the energy, energy technology and financial services sectors and his in-depth knowledge of the issues, challenges, and opportunities facing us.

Robert Pender

Robert (Bob) Pender is one of the Company’s co-founders. Mr. Pender has served as an Executive Co-Chairman of the Company’s board of directors since September 2023. Prior to October 2020, Mr. Pender served as Co-Chief Executive Officer of VGLNG. Mr. Pender has also served as an officer of VGLNG as Executive Co-Chairman since October 2020 and as an Executive Co-Chairman of VGLNG’s board of directors since August 2014. Mr. Pender was also Co-Managing Partner of Legacy VG Partners since 2012, until Legacy VG Partners merged with the Company, and is currently Co-Managing Partner of VG Partners, the Company’s controlling shareholder. Mr. Pender previously practiced law for over 28 years, specializing in alternative energy project finance, including during the early years of the sustainable energy transition in the U.S. Mr. Pender has worked on over $35 billion of energy, infrastructure and power projects, including cogeneration, biomass, wind, hydro, geothermal, LNG and nuclear. Prior to founding VGLNG, Mr. Pender previously served as a partner at Hogan Lovells, a global law firm, where he was the Chair and Practice Group Director of its Project &

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International Finance Group for a decade. Mr. Pender has led large-scale energy infrastructure transactions throughout North America, Central and South America, and South Asia, including representations of nation states, such as the Government of India (through its Ministry of Power), the Republics of Ecuador and Guyana and the Peoples Republic of China (through its SOEs, Sinosure and China Development Bank), lenders, equity investors and developers. Mr. Pender also provided several years of pro bono support to the Republic of Haiti, among others, the American Red Cross for tsunami relief in South Asia, Accion for micro-finance capital projects in Africa and beginning with legal support to the Interim Haiti Recovery Commission, then serving as a counselor to the Minister Delegate for Energy Security, Republic of Haiti. We believe Mr. Pender is qualified to serve as director due to his experience as one of our co-founders, his decades of experience in law related to alternative energy project finance, and his experience leading large-scale energy infrastructure transactions both domestically and internationally.

Jonathan Thayer

Jonathan (Jack) Thayer has served as the Company’s Chief Financial Officer since September 2023 and has served as VGLNG’s Chief Financial Officer since June 2020. Mr. Thayer has over 25 years of finance, strategy and mergers & acquisition leadership experience including serving as Chief Financial Officer at two Fortune 500 energy companies. Prior to joining VGLNG, he served as Vice Chairman, Corporate Operations and Chief Financial Officer from 2019 to 2020 of Woodward, Inc. (Nasdaq: WWD), an independent designer, manufacturer, and service provider of control system solutions and components for the aerospace and industrial markets, as Chief Financial Officer from 2012 to 2018 of Exelon Corporation (Nasdaq: EXC), a leading utility, power marketing and generation holding company, and, from 2008 to 2012, Chief Financial Officer of Constellation Energy Group, Inc. (Nasdaq: CEG), a large, integrated energy company, with power generation, gas and electric distribution utilities and energy marketing and risk management services. Mr. Thayer has also held roles in investment banking, first with SBC Warburg Dillon Read, and subsequently with Deutsche Bank Securities.

Brian Cothran

Brian Cothran has served as VGLNG’s Chief Operating Officer since September 2020. Mr. Cothran is an accomplished business leader with over 25 years of project, operational and strategic experience in the Oil & Gas and Power Generation industries. Most recently, Mr. Cothran served from 2019-2020 as Chief Executive Officer of The Flexitallic Group, a global market leader in the manufacture and supply of static sealing solutions. Prior to joining Flexitallic, Mr. Cothran served more than 20 years, from 1998-2019, with General Electric (NYSE: GE) and Baker Hughes (Nasdaq: BKR), after its merger with GE Oil & Gas in 2017. During that time, he held a number of senior executive and management roles both in the United States and abroad, which included leading GE’s Energy Services business in Eastern Europe, General Manager of GE’s Flow and Process Technologies business in Europe, Vice President of Global Sales for Baker Hughes and President of GE Oil & Gas North America.

Fory Musser

Fory Musser has served as VGLNG’s Senior Vice President, Development since January 2015 and initially joined VGLNG as its Vice President, Development in September 2014. Before joining VGLNG, Mr. Musser was the Vice President, Corporate Development for Tervita Corporation, a privately held, leading provider of environmental services to the oil and gas industry in North America. In his four years at Tervita, Mr. Musser’s primary responsibilities included strategic planning, executing corporate acquisitions and divestitures and restructuring the company’s drilling and coring business. Before joining Tervita, Mr. Musser served for more than two years as the Vice President, Strategy for Covanta Energy, one of the world’s largest owners and operators of energy-from-waste facilities. Mr. Musser’s primary responsibilities at Covanta included strategic planning, executing corporate acquisitions, and developing new lines of business that complemented existing

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operations. Prior to joining Covanta Energy, Mr. Musser worked at AES (NYSE: AES), in a variety of roles, principally focused on project financing, business development, and subsidiary debt restructuring. Before AES, Mr. Musser was a banker in the private placement group at Deutsche Bank Alex Brown.

Keith Larson

Keith Larson has served as the Company’s General Counsel and Secretary since September 2023 and has served as VGLNG’s General Counsel and Secretary since July 2017. Prior to joining VGLNG, Mr. Larson spent 10 years as a partner at Hogan Lovells, a global law firm, where he headed the firm’s infrastructure, energy, resources and projects practice for the Americas. Mr. Larson has over 25 years of experience advising on energy project development, project finance and strategic transactions in the oil and gas sector. Mr. Larson’s prior experience includes serving as Senior Legal Counsel for Shell (NYSE: SHEL) in The Hague.

Thomas Earl

Thomas Earl has served as Chief Commercial Officer of VG LNG Marketing, LLC since 2017. Prior to joining the Company, Mr. Earl worked for Total (NYSE: TTE) from 1998 to 2017, where he focused on the development of Total’s global LNG business, where he most recently served as head of Total’s North America commodity trading business, including its LNG, gas, power, coal, petcoke and LPG operations, and represented Total in its U.S. LNG liquefaction transactions from 2012 to 2015.

Sari Granat

Sari Granat has served on the Company’s board of directors since September 2023 and has served on VGLNG’s board of directors since January 2022. Ms. Granat has been president and chief operating officer of Chainalysis since 2022, the blockchain data platform, where she has managed the company’s general and administrative functions, including finance, human resources, legal, information security and information technology and the company’s sales organization. At Chainalysis, Ms. Granat works across the firm on strategies to advance the company’s mission of bringing trust and transparency to the global cryptocurrency community. In addition, Ms. Granat, from October 2021 and October 2022, served on the board of ComplySci, a provider of regulatory technology solutions for the financial services sector, and she currently serves on the boards of Assurant, Inc. (NYSE: AIZ), a global provider of risk management products and services, where she serves on the board’s Compensation and Talent Committee and Information Technology Committee. Ms. Granat has also served on the board of Opening Act, a nonprofit that advances arts equity by providing free theater programs to New York City’s highest need public schools, the CxO Advisory Council for VMware and on the General Counsel Steering Committee for the National Association of Corporate Directors. From 2012 to 2022, Ms. Granat was with IHS Markit, a formerly NYSE-listed $45+ billion data, analytics and technology company prior to its merger with S&P Global in February 2022, where she most recently served as chief administrative officer and general counsel, leading information security, information technology, legal, risk management, privacy and compliance functions. From 2010 to 2012, Ms. Granat was chief administrative officer and head of business development at TheMarkets.com LLC, a financial technology and data provider. Prior to that role, Ms. Granat has served in a variety of legal and strategy positions with Dow Jones & Company, Kaplan, Inc., Skadden, Arps, Slate, Meagher & Flom LLP, and Kenyon & Kenyon. We believe Ms. Granat is qualified to serve as director due to her significant leadership and management experience within the financial technology and data analytics sectors, including her experience of more than 10 years general counsel of public companies and in risk management, privacy and information technology.

Andrew Orekar

Andrew Orekar has served on the Company’s board of directors since September 2023 and has served on VGLNG’s board of directors since September 2021. Mr. Orekar is the former Chief Executive Officer and Board Member of GasLog Partners (NYSE: GLOP-A), one of the world’s largest LNG shipping companies. Appointed

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CEO at GasLog Partners’ founding in 2014, Mr. Orekar led the company’s IPO and oversaw its growth from three to fifteen vessels during his nearly seven years as CEO. Mr. Orekar worked at GasLog Partners in his capacity as CEO until 2020. Prior to joining GasLog Partners, Mr. Orekar served as Managing Director at Goldman, Sachs & Co., where he advised natural resources companies on mergers and acquisitions and capital markets transactions. Mr. Orekar joined Goldman Sachs in 1998 and held several leadership positions in the investment banking division. Mr. Orekar also previously served on the boards of directors of Tortoise Acquisition Corp. and Parabola Acquisition Corp. We believe Mr. Orekar is qualified to serve as director due to his extensive public company leadership experience in the LNG and maritime transport sectors and his deep knowledge of corporate transactions within the energy, shipping and financial services industries.

Thomas J. Reid

Thomas Reid has served on the Company’s board of directors since September 2023 and has served on VGLNG’s board of directors since January 2022. Mr. Reid is chief legal officer and secretary of Comcast Corporation (Nasdaq: CMCSA), a position he has held since April 2019. Mr. Reid oversees Comcast’s legal, corporate governance and strategic intellectual property functions and the company’s government and regulatory affairs and political affairs functions. Mr. Reid joined Comcast in 2019 after a successful career at Davis Polk & Wardwell, LLP. Mr. Reid began his career there in 1987 and served as chairman and managing partner of the firm from 2011 until his transition to Comcast. Mr. Reid also served as a Managing Director in the Investment Banking division of Morgan Stanley from 2000-2003. Mr. Reid’s private legal practice and banking career were heavily focused on the global energy and utilities sector, advising on privatizations, mergers and acquisitions, financings and board investigations for leading international oil and gas companies and national oil companies. Mr. Reid serves as trustee for the Archdiocese of New York’s Inner-City Scholarship Fund and as a trustee of the National Urban League. We believe Mr. Reid is qualified to serve as director due to his extensive leadership experience in legal advisory roles, including his role at public companies, law firms, and investment banks, as well as his deep knowledge of the global energy and utilities sector.

Jimmy Staton

Jimmy Staton has served on the Company’s board of directors since September 2023 and has served on VGLNG’s board of directors since August 2014. Mr. Staton was formerly VGLNG’s Executive Vice President from January 2015 to November 2016. Mr. Staton is currently the President and Chief Executive Officer of the South Carolina Public Service Authority (Santee Cooper), a state owned electric and water utility company that provides power directly or indirectly to 2 million South Carolinians and clean water to over 200,000 customers, and has served in such capacity since March 2022. Prior to this, Mr. Staton served as President and CEO of Southern Star Central Corporation, a privately held natural gas pipeline company with assets throughout the Midwest United States, from 2017 to 2022. Additionally, Mr. Staton also served as Executive Vice President and Group CEO for NiSource, Inc. (NYSE: NI) from 2008 to 2014. Prior to his tenure at NiSource, Mr. Staton held several senior executive level positions at Dominion Resources, Inc. (NYSE: D) from 1993 to 2008. Mr. Staton has also been active in industry organizations having served on the Board of Directors for the Edison Electric Institute, the Interstate Natural Gas Association of America, the American Gas Association, the American Gas Foundation and the Southern Gas Association. We believe Mr. Staton is qualified to serve as director due to his extensive experience in the utilities sector, including leadership roles in gas distribution, electric and gas utilities and interstate gas pipelines businesses.

Roderick Christie

Roderick Christie has served on the Company’s board of directors since September 2023 and has served on VGLNG’s board of directors since June 2023. Mr. Christie is a veteran of the electricity and energy sectors, with over 30 years of international experience. From September 2022 to January 2023, Mr. Christie was Executive Vice President of Baker Hughes (Nasdaq: BKR), Industrial & Energy Technology business where he worked with business developments, manufactures and services of a wide range of technologies for the energy, aviation

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and automotive industries. Prior to that, from January 2016 to September 2022, Mr. Christie was Executive Vice President of Baker Hughes Turbomachinery and Process Solutions business. In 2017, Mr. Christie created and led the Baker Hughes Climate Technology Solutions, developing solutions for hydrogen, CCUS, integrated clean energy, and emissions management to support customers’ net-zero emission ambitions and latterly integrated the Baker Hughes Controls, Sensing and Diagnostics businesses to create the Baker Hughes Industrial & Energy Technology Business. From June 2018 to February 2023, Mr. Christie served as a member of the board at Aero Alliance Products & Services LLC. Prior to Baker Hughes, Mr. Christie was President & CEO of GE Energy Subsea Solutions from June 2011 to December 2016, President of GE Energy Central & Eastern Europe, Russia and Central Asia from September 2004 to June 2011 and CEO of GE Energy Services Europe from June 1999 to September 2004. Before joining GE, he worked for 14 years at Scottish & Southern Energy (LSE: SSE) in the utility power sector, where he held a wide range of engineering, project development and management roles. Accordingly, Mr. Christie has developed significant global experience in the oil & gas, gas processing, LNG, refining, petrochemical and electricity sectors. We believe Mr. Christie is qualified to serve as director due to his decades of international experience in the electricity and energy sectors, and his extensive public company leadership experience within the energy industry.

Other Key Employees

Set forth below is certain biographical and other information regarding our other key employees as of , 2024:


Name	Age	Position
Leah Woodward		Treasurer and Managing Director
Sarah Blake		Senior Vice President and Chief Accounting Officer
Ngoni Murandu		Chief Information Officer

Leah Woodward

Leah Woodward has served as the Company’s Treasurer since September 2023 and has served as VGLNG’s Treasurer and Managing Director since January 2020 and June 2017, respectively, and oversees Venture Global’s capital markets, treasury, corporate strategy and development, and investor relations activities. Ms. Woodward has more than 18 years of experience across the capital structure and has worked with Venture Global’s founders since 2014 to raise over $51 billion of capital for the business. This includes the Calcasieu Pass and Plaquemines project financings, representing more than $29 billion of total investment, as well as more than $15 billion of high-yield bond issuances. Prior to joining Venture Global, from 2009 to 2017, Ms. Woodward was a Managing Director and the Head of Institutional Sales at Height Capital Markets, a Washington, D.C.-based broker-dealer and investment bank, and in that capacity worked on Venture Global’s inaugural capital raises. Before joining Height Capital Markets, Ms. Woodward worked in fixed income at BNP Paribas, a global bank, from 2006 until 2008. She earned her Chartered Financial Analyst (CFA) charter in 2010.

Sarah Blake

Sarah Blake has served as VGLNG’s Senior Vice President and Chief Accounting Officer since January 2020, and focuses on financial transformation, SEC reporting and technical accounting. Ms. Blake has over 25 years of accounting experience across a wide range of businesses and firms. Prior to joining VGLNG, Ms. Blake served in various capacities at The AES Corporation (NYSE: AES) from 2006 to 2020, most recently in her capacity as Vice President, Controller and Chief Accounting Officer from 2017 to 2020. Ms. Blake currently is a licensed Certified Public Accountant in Virginia.

Ngoni Murandu

Ngoni Murandu has served as VGLNG’s Chief Information Officer since August 2019. He focuses particularly on information technology systems in the energy sector. Mr. Murandu has over 25 years of experience in the information technology industries, and has installed, maintained and managed large enterprise

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resource applications for a wide range of businesses. Prior to joining VGLNG, Mr. Murandu served as the Vice President of Information Technology Services and the Chief Information Officer at Southwest Gas Corporation (NYSE: SWX) from May 2017 to August 2019. Prior to Southwest Gas Corporation, Mr. Murandu served as the Vice President and Chief Information Officer at NW Natural (NYSE: NWN) from May 2014 to May 2017.

Family Relationships

There are no family relationships among any of the directors or executive officers.

Status as a “Controlled Company” under Listing Standards

After the completion of this offering, VG Partners will continue to hold approximately % of the total combined voting power of our Class A common stock and Class B common stock eligible to vote in the election of directors. As a result, we will be a “controlled company” for the purposes of the listing requirements.

As a “controlled company,” we may elect not to comply with certain corporate governance standards under the rules of , including the requirements (i) that a majority of our board of directors consist of independent directors, (ii) that our board of directors have a compensation committee that is comprised entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities, (iii) that our board of directors have a nominating and governance committee that is comprised entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities, and (iv) that our board of directors conduct an annual performance evaluation of the nominating and governance committee and the compensation committee. For at least some period following this offering, we intend to utilize these exemptions.

Consistent with these exemptions, upon closing this offering, we will not have . However, despite being a “controlled company,” we are required to comply with the rules of the SEC and the relating to the membership, qualifications and operations of the audit committee. Upon closing this offering, we will have a fully independent audit committee. Additionally, we have adopted charters for our audit, compensation, nominating and governance committees and intend to conduct annual performance evaluations of these committees.

Accordingly, although we may transition to fully independent compensation and nominating and governance committees prior to the time we cease to be a “controlled company,” for such period of time you will not have the same protections afforded to shareholders of companies that are subject to all of these corporate governance requirements. In the event that we cease to be a “controlled company” and our shares continue to be listed on , we will be required to comply with these provisions within the applicable transition periods.

Board Structure and Compensation of Directors

Board Composition

Our amended and restated certificate of incorporation and amended and restated bylaws will provide that the board of directors shall consist of not less than directors, nor more than directors, and the number of directors may be changed only by resolution of the board of directors. Upon completion of the offering, our board of directors will consist of members.

Initially, our board of directors will consist of a single class of directors each serving one year terms. Once we would fail to qualify as a “controlled company” under the rules, our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms (other than directors which may be elected by holders of preferred stock, if any). This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors because, in general, at least two annual meetings of stockholders would be necessary for stockholders to effect a change in a majority of the members of the board of directors.

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Director Independence

We intend to avail ourselves of the “controlled company” exception under the rules, which allows us to elect not to comply with the requirements that a listed company must have a majority of independent directors on its board of directors and that its compensation and nominating and governance committees be composed entirely of independent directors. Notwithstanding such election, our board of directors has reviewed the materiality of any relationship that each of our directors has with us, either directly or indirectly. Based on this review, our board has determined that each of , and is independent under applicable rules and Rule 10A-3 of the Exchange Act.

Board Committees

Following the completion of this offering, our board will establish three standing committees—audit, compensation and nominating and governance—each of which will operate under a charter that will be approved by our board. Current copies of each committee’s charter will be posted on the Corporate Governance section of our website at www.venturegloballng.com. Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this prospectus or the registration statement of which it forms a part and is included in this prospectus as an inactive textual reference only.

Audit Committee

The members of our audit committee are , and , with serving as the chairman of our audit committee. Each member of our audit committee has been determined by the board to satisfy the independence requirements for audit committee members under the listing standards of the and Rule 10A-3 of the Exchange Act, and to meet the financial literacy requirements under the rules and regulations of the and the SEC. In addition, our board of directors has determined that is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of Regulation S-K promulgated under the Securities Act of 1933, as amended, or the Securities Act. This designation does not impose on him or her any duties, obligations or liabilities that are greater than are generally imposed on members of our audit committee and our board of directors. Our audit committee is directly responsible for, among other things:

•

selecting a firm to serve as the independent registered public accounting firm to audit our financial statements;

•

ensuring the independence of the independent registered public accounting firm;

•

discussing the scope and results of the audit with the independent registered public accounting firm and reviewing, with management and that firm, our interim and year-end operating results;

•

establishing procedures for employees to anonymously submit concerns about questionable accounting or audit matters;

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considering the adequacy of our internal controls and internal audit function;

•

reviewing material related party transactions or those that require disclosure; and

•

approving or, as permitted, pre-approving all audit and non-audit services to be performed by the independent registered public accounting firm.

Our audit committee will operate under a written charter, to be effective immediately prior to the closing of this offering, that satisfies the applicable rules of the SEC and the listing standards of the .

Compensation Committee

The members of our compensation committee are , and . is the chairman of our compensation committee. Our compensation committee is responsible for, among other things:

•

reviewing and approving, or recommending that our board of directors approve, the compensation of our executive officers;

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•

reviewing and recommending to our board of directors the compensation of our directors;

•

administering our stock and equity incentive plans;

•

reviewing and approving, or making recommendations to our board of directors with respect to, incentive compensation and equity plans; and

•

reviewing our overall compensation philosophy.

Our compensation committee will operate under a written charter, to be effective immediately prior to the closing of this offering, that satisfies the applicable rules of the SEC and the listing standards of the .

Nominating and Governance Committee

The members of our nominating and governance committee are , and . is the chairman of our nominating and governance committee. Our nominating and governance committee is responsible for, among other things:

•

identifying and recommending candidates for membership on our board of directors;

•

reviewing and recommending our corporate governance guidelines and policies;

•

reviewing proposed waivers of the code of conduct for directors and executive officers;

•

overseeing the process of evaluating the performance of our board of directors; and

•

assisting our board of directors on corporate governance matters.

Our nominating and governance committee will operate under a written charter, to be effective immediately prior to the closing of this offering, that satisfies the applicable rules of the SEC and the listing standards of the .

Code of Ethics

In connection with this offering, our board of directors will adopt a code of ethics that applies to all of our employees, officers and directors, including our Co-Chairmen, Chief Executive Officer, Chief Financial Officer and other executive and senior financial officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of . Upon completion of this offering, the full text of our codes of business conduct and ethics will be posted on the investor relations section of our website. We intend to disclose future amendments to our codes of business conduct and ethics, or any waivers of such code, on our website or in public filings.

Corporate Governance Guidelines

Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of .

Compensation Committee Interlocks and Insider Participation

of our executive officers has served as a member of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors.

To the extent any members of our compensation committee and affiliates of theirs have participated in transactions with us, a description of those transactions is described in “Certain Relationships and Related Person Transactions.”

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EXECUTIVE COMPENSATION

Compensation Discussion And Analysis

The purpose of this Compensation Discussion and Analysis section is to provide information about the material elements of compensation that, during our fiscal year ended December 31, 2023, were paid to, awarded to, or earned by our “named executive officers”, or NEOs, who consist of our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers during our 2023 fiscal year.

Our named executive officers for fiscal 2023 are:

•

Michael Sabel, Chief Executive Officer, Founder, and Executive Co-Chairman of the Board and Director;

•

Jonathan Thayer, Chief Financial Officer;

•

Robert Pender, Executive Co-Chairman, Founder, and Executive Co-Chairman of the Board and Director;

•

Thomas Earl, Chief Commercial Officer; and

•

Keith Larson, General Counsel and Secretary.

As noted above, this Compensation Discussion and Analysis section describes our historical executive compensation program for our named executive officers during our 2023 fiscal year. In connection with this offering, we intend to adopt compensation plans typical for public companies and we expect that, after our initial public offering, our compensation committee will set policies and practices that may be different from the policies and practices that applied to our executive officers before our initial public offering.

Our Compensation Philosophy

Our company strives to be a leader in compensation relative to our industry peers in order to attract the best talent, and our executive compensation programs are designed to attract, motivate and retain a highly talented senior management team capable of deploying best-in-class industry expertise to deliver competitively priced, reliable and clean North American LNG exports on a growing scale. The following principles help guide us in designing our pay programs toward this end:

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Competitive Pay: Our goal is to attract and maintain the best talent in our industry by paying above-market total compensation. We will review “market” total compensation and, over time, target each executive competitively within the market based upon our assessment of a variety of factors including individual performance, company-wide performance, time in role, individual skills and importance of the role. Generally, our philosophy is to place more compensation in cash-based incentive opportunities, which are tied to key project-based milestones reflecting our long-term business objectives, as well as year-over-year individual performance goals. As noted above, actual pay delivered will vary based on both company-wide and individual performance. The elements of our compensation programs are discussed in greater detail below.

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Significant Pay at Risk: As noted above, a significant portion of the total compensation of our executives should be variable and at risk, which is primarily accomplished through our cash and equity incentive compensation programs. We will pay our NEOs higher compensation when they exceed our goals and lower compensation when they do not meet our goals.

•

Alignment with Shareholder Interests: The interests of our executives should align with the interests of our shareholders. Our short- and long-term incentive compensation programs utilize a performance-based mentality that correlates well with the creation of shareholder value.

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•

Support Business Strategy: Our executive compensation programs are aligned with our short-term and long-term business objectives, business strategy and company-wide financial and operational performance, furthering the creation of shareholder value.

•

Risk Management: We believe that our compensation policies and practices appropriately balance near-term performance improvement with sustainable long-term value creation and that they do not encourage unnecessary or imprudent risk taking. We continuously evaluate the design of all our compensation policies and practices, including our incentive plans, to assess whether they encourage employees to take appropriate risks and discourage taking inappropriate risks.

Compensation Process

Historically, the compensation of our Founders, Messrs. Sabel and Pender, has been set by our board of directors and, since October 2020, the compensation of our executive officers other than the Founders has been set by Mr. Sabel in his capacity as our Chief Executive Officer. In anticipation of becoming a public company, our board of directors will adopt a written charter for the compensation committee that establishes, among other things, the compensation committee’s purpose and its responsibilities with respect to executive compensation. The charter of the compensation committee will provide that the compensation committee shall, among other things, review and approve, or recommend to our board of directors, as appropriate, executive officer compensation, and otherwise assist our board of directors in its oversight of executive compensation, management development and succession, director compensation and executive compensation disclosure.

In connection with becoming a public company, we intend to engage an outside compensation consultant to advise the compensation committee with respect to go-forward executive compensation programs, policies and decisions.

Elements of Compensation

Historically, our executive compensation programs have consisted of the following elements: base salary, short- and long-term, as well as milestone-based, cash incentive compensation, equity incentive compensation, health, welfare and retirement benefits and perquisites, each established as part of our programs in order to achieve our compensation objectives.

Annual Base Salary

Base salary is intended to fairly compensate our NEOs for the responsibilities of their respective positions and achieve an optimal balance of fixed and variable pay. In setting the salaries of individual NEOs, we consider a wide range of factors including the scope of the NEO’s role, experience, skillsets and the compensation paid for similar positions at other companies similar to ours. The 2023 base salaries for our NEOs were as follows:


Name	2023 Base Salary
Michael Sabel	$	7,500,000	⁽¹⁾
Jonathan Thayer	$	1,500,000
Robert Pender	$	3,500,000	⁽¹⁾
Thomas Earl	$	1,500,000
Keith Larson	$	1,500,000

(1)	In 2023, each of Mr. Sabel and Mr. Pender received a base salary for services he provided to certain of our subsidiaries, which were paid by each such subsidiary. These amounts reflect the aggregate base salary rates in effect as of December 31, 2023.

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Cash Incentive Compensation Arrangements

In order to incentivize and reward performance, we maintain various cash incentive opportunities for our executives, including our NEOs, which pay out based on the achievement of certain financial and operating performance objectives and our key strategic priorities. We believe these opportunities reflect a well-balanced framework for motivating our key personnel to execute on our strategic priorities while being recognized for their individual contributions to our short- and long-term growth.

Annual Cash Performance Bonus

Our NEOs are eligible to receive cash-based annual performance bonuses based on a qualitative evaluation of individual and Company performance following the applicable performance year, including with respect to achievement of strategic milestones and financial performance. At the end of each year, the Chief Executive Officer assesses such performance and provides a recommendation to our board of directors as to each NEO’s annual performance bonus amount, including his own. The Company believes that this approach provides an opportunity to balance our annual financial and operational achievements with qualitative judgments regarding how individual performance goals were achieved and ensures appropriate and balanced outcomes once all relevant facts are known following the end of a fiscal year. As the Company matures over time, the compensation committee will continue to evaluate its compensation programs and criteria with a focus on aligning short-term incentive compensation to achievement of performance-specific outcomes for a given year. Annual performance bonuses are generally payable in April of the year following the year for which the bonus is earned, subject to the NEO’s continued employment with us through the payment date. Annual performance bonuses earned by our NEOs for the 2023 fiscal year were as follows:


Name	2023 Bonus
Michael Sabel	$	25,000,000
Jonathan Thayer	$	2,000,000
Robert Pender	$	25,000,000
Thomas Earl	$	2,000,000
Keith Larson	$	2,000,000

Project Milestone Bonuses

Project Milestone Bonuses constitute an important part of our compensation philosophy by rewarding successful completion of key strategic objectives.

Each NEO is eligible to earn certain cash bonuses, or Project Milestones Bonuses, upon the successful completion of significant milestones with respect to the development of our natural gas liquefaction and export facilities. For each export facility project or phase, a Project Milestone Bonus is earned upon the completion of three milestones as follows:

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FID: Earned upon the board of directors’ determination that, with respect to any project or phase, the following conditions have been satisfied: (i) the project has received all necessary regulatory authorizations, including from FERC, to commence construction; (ii) the project has secured sufficient financing for construction and funds are available from lenders for disbursement thereunder; and (iii) the project has received approval from the board of directors to proceed with the construction.

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LPS: Earned on the date on which, with respect to any project or phase, the performance acceptance tests for a certain number of liquefaction trains of the project or phase have been successfully passed and such liquefaction trains have initiated continuous operation producing liquefied natural gas for sale.

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COD: Earned as of COD for the relevant project or phase.

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Project Milestone Bonuses are generally payable in connection with the completion of each milestone noted above, subject in each case to the NEO’s continued employment through such date. In certain cases, the bonuses are paid in equal quarterly installments over a one-year period, subject to the NEO’s continued employment through each payment date.

The following table sets forth, for each of our NEOs, the aggregate Project Milestone Bonus opportunity as of January 1, 2023, any amounts awarded in 2023, any amounts paid in 2023, and the outstanding bonus opportunity as of December 31, 2023.


Name	Outstanding as of January 1, 2023⁽¹⁾		Granted in 2023		Paid in 2023			Outstanding as of December 31, 2023
Michael Sabel	$	3,000,000	$	9,000,000	$	1,000,000	⁽²⁾	$	11,000,000
Jonathan Thayer	$	10,000,000		—	$	1,000,000	⁽²⁾	$	9,000,000	⁽⁵⁾
Robert Pender	$	3,000,000	$	9,000,000	$	1,000,000	⁽²⁾	$	11,000,000
Thomas Earl	$	8,250,000		—	$	1,250,000	⁽³⁾	$	7,000,000	⁽⁵⁾
Keith Larson	$	10,125,000		—	$	1,125,000	⁽⁴⁾	$	9,000,000	⁽⁵⁾

(1)	Represents Project Milestone Bonuses outstanding relating to the achievement of significant milestones with respect to the achievement of FID, LPS and/or COD milestones with respect to the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, and/or the Delta Project.

(2)	Represents a lump sum payment of a Project Milestone Bonus earned in 2023.

(3)	$1,000,000 of this amount represents a lump sum payment of a Project Milestone Bonus earned in 2023 and $250,000 of this amount represents the final installment payment of a $1,000,000 Project Milestone Bonus which was paid out in four equal quarterly installments over a 12-month period.

(4)	$1,000,000 of this amount represents a lump sum payment of a Project Milestone Bonus earned in 2023 and $125,000 of this amount represents the final installment payment of a $500,000 Project Milestone Bonus which was paid out in four equal quarterly installments.

(5)	Each Project Milestone Bonus that becomes earned will be paid in four equal quarterly installments over a 12-month period.

Strategic Recognition Awards

The Company has also granted strategic recognition awards to the NEOs, other than Messrs. Sabel and Pender, which are structured as deferred bonus awards designed to motivate sustained service with us over an extended period, or the Strategic Recognition Awards. In 2022 and 2023, each of Messrs. Thayer, Larson and Earl received a Strategic Recognition Award in the amount of $2,000,000 and $3,000,000, respectively. The Strategic Recognition Awards are payable in equal quarterly installments over a four-year period, subject to the NEO’s continued employment with us through each payment date. The Strategic Recognition Awards earned by each such NEO in 2023 was as follows:


Name	2023 Strategic Recognition Award Paid
Jonathan Thayer	$	875,000
Thomas Earl	$	875,000
Keith Larson	$	875,000

Major Revenue Contract Bonuses

Another element of our compensation philosophy is recognizing the accomplishments of employees in contributing to our sustained long-term growth and development. Accordingly, we compensate employees who primarily focus on marketing our business for their critical roles in negotiating and successfully executing major revenue contracts for liquefied natural gas, or Revenue Contract Bonus.

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Of our NEOs, only Mr. Earl is eligible to receive a Revenue Contract Bonus. The Revenue Contract Bonus is earned upon execution of a sales and purchase agreement pursuant to which a specified amount of liquefied natural gas is committed to be purchased over an extended contract term. Payment of the bonus is subject to Mr. Earl’s continued employment on the date of execution of such contract and payable within 30 days thereof.

In 2023, Mr. Earl earned aggregate Revenue Contract Bonuses in the amount of $695,000.

Long-Term Equity Incentive Compensation

We view long-term equity incentive compensation as a critical component of our balanced total compensation program and a primary means to incentivize our employees to contribute to the long-term growth and development of our business. For us, this has historically taken the form of non-qualified stock option grants under the Venture Global LNG, Inc. 2014 Stock Option Plan, as amended and restated from time to time, or the 2014 Plan, and its successor plan, the Venture Global, Inc. 2023 Stock Option Plan, or the 2023 Plan. In connection with the Reorganization Transactions, all options that were previously granted and outstanding under the 2014 Plan were converted, on a one-for-one basis, into stock options with respect to shares of our Class A common stock under the 2023 Plan and remain outstanding under the 2023 Plan. The material terms of the 2023 Plan are described under “— 2023 Stock Option Plan” below.

Stock options granted to our NEOs pursuant to our equity incentive program vest in equal quarterly installments over a four-year period from the grant date, subject to the executive’s continued employment with us through each vesting date and expire on the 10^th anniversary of the grant date. In 2023, none of our NEOs received a grant of stock options under the 2014 Plan or the 2023 Plan.

In connection with this offering, we intend to adopt a new omnibus incentive plan, under which our employees (including our NEOs) may receive long-term incentive compensation in the future.

Other Benefits and Perquisites

We provide benefits, including personal benefits and perquisites, to our NEOs as summarized below. We believe that these benefits are necessary and appropriate to enable us to attract and retain top talent within a competitive marketplace and to facilitate the performance of our NEOs’ management responsibilities.

Personal Security

We provide personal security services for Mr. Sabel, which is based on an assessment of risk in light of his position as our Chief Executive Officer. These services generally include security systems at Mr. Sabel’s residence, security services and personnel at his residences and/or during personal travel and car and personal security driver. While we do not consider these security costs to be personal benefits since they arise from the nature of Mr. Sabel’s employment with our Company, certain amounts that are paid by us are considered to constitute perquisites and personal benefits for purposes of SEC disclosure rules and are reported in the Summary Compensation Table under the “All Other Compensation” column below based on the aggregate incremental cost to the Company to provide these services.

Corporate Aircraft Policy

We encourage use of our corporate aircraft for the personal travel of our Co-Chairmen and Founders because it increases their time available for business purposes and enhances their safety and security. The aggregate incremental cost to us for personal use of the corporate aircraft and the total number of hours the NEO used the aircraft in 2023, calculated based on the hourly variable cost rate for personal use of the aircraft, including fuel, airport fees, crew expenses and in-flight catering is reported in the Summary Compensation Table under the “All Other Compensation” column below.

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Retirement and Health and Welfare Benefits

We maintain a tax-qualified defined contribution plan (the “401(k) Plan”) in which our employees, including our NEOs (other than Mr. Earl), are eligible to participate. Under the 401(k) Plan, participants may defer a portion of their annual compensation on a pre-tax basis, and we will make matching contributions of 100% of the first 6% of a participant’s deferrals. All of our full-time employees, including our NEOs, are also eligible to participate in customary health and welfare plans, except for Mr. Earl, who is based in the UK. In lieu of his participation in the health and welfare plans generally available to our employees, we provide Mr. Earl with a monthly stipend in the amount of $3,000 to cover his health and welfare expenses. In addition, we provided contributions to Mr. Earl’s pension in an amount equal to $1,640 in 2023.

Executive Employment Agreements

Prior to becoming a public company, we intend to enter into employment agreements with each of our NEOs which will provide for compensation and benefits, including severance protections, typical of those provided to executive officers of a public company, the terms of such agreements will be described following entry into the agreements.

Restrictive Covenant Agreements

Each of our NEOs, other than Messrs. Sabel and Pender, is party to a restrictive covenant agreement, which generally provides for restrictions on non-competition (during employment and for 18 months thereafter in the case of Mr. Thayer and six months thereafter in the case of Messrs. Earl and Larson), non-solicitation and no-hire of employees and non-solicitation of customers or clients (during employment and for 18 months thereafter in the case of Mr. Thayer and six months thereafter in the case of Messrs. Earl and Larson), confidentiality with respect to Company confidential information (during employment and for five years thereafter), in the case of Messrs. Thayer and Earl only, confidentiality with respect to trade secrets (in perpetuity), assignment of intellectual property and non-disparagement (in perpetuity).

Tax and Accounting Considerations

When reviewing compensation matters, we consider the anticipated tax and accounting consequences to us (and, when relevant, to our executive officers) of the various payments under our compensation programs. Section 162(m) of the Internal Revenue Code of 1986, as revised (the “Code”) generally limits the tax deductibility of annual compensation paid by public companies for certain executive officers to $1 million. Although we are mindful of the benefits of tax deductibility when determining executive compensation, we may approve compensation that will not be fully-deductible in order to ensure competitive levels of total compensation for our executive officers. We account for stock-based payments, including grants of options under our stock option plan, in accordance with the requirements of FASB ASC Topic 718.

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Executive Compensation Tables

Summary Compensation Table

The following table sets forth information concerning the compensation paid to our NEOs during our fiscal year ended December 31, 2023.


Name and Principal Position	Year		Salary ($)		Bonus ($)⁽¹⁾		All Other Compensation ($)⁽²⁾		Total ($)
Michael Sabel Chief Executive Officer, Executive Co-Chairman and Founder		2023		5,584,790		26,000,000		1,997,026		33,581,816
Jonathan Thayer Chief Financial Officer		2023		1,500,000		3,875,000		20,150		5,395,150
Robert Pender Executive Co-Chairman and Founder		2023		2,498,252		26,000,000		37,967		28,536,219
Thomas Earl Chief Commercial Officer		2023		1,500,000		4,820,000		37,640		6,357,640
Keith Larson General Counsel and Secretary		2023		1,500,000		4,000,000		20,150		5,520,150

(1)

Amounts reported include (i) a 2023 annual performance bonus in the amount of $25,000,000 for each of Messrs. Sabel and Pender and $2,000,000 for each of Messrs. Thayer, Earl and Larson, (ii) payment of Project Milestone Bonuses equal to $1,000,000 for each of Messrs. Sabel, Thayer and Pender, $1,250,000 for Mr. Earl and $1,125,000 for Mr. Larson; (iii) payment of Strategic Recognition Awards in an amount equal to $875,000 for each of Messrs. Thayer, Earl and Larson; and (iv) for Mr. Earl, Revenue Contract Bonuses equal to $695,000. For additional information on our cash incentive programs, please see “—Cash Incentive Compensation Arrangements” above.

(2)

Amount reported includes, as applicable, (i) the value of perquisites and personal benefits (as defined by the SEC), including (A) payments made by the Company on behalf of Mr. Sabel for costs related to personal security at his residences in the amount of $1,840,281, (B) costs related to personal use of the corporate aircraft by Messrs. Sabel and Pender in the amount of $136,595 and $17,817, respectively, and (C) reserved parking allowances in the amount of $350 for each NEO; (ii) 401(k) matching contributions on behalf of our NEOs, other than Mr. Earl, in the amount of $19,800 each; (iii) monthly stipends paid to Mr. Earl for health and welfare benefits in the amount of $36,000 and (iv) contributions to Mr. Earl’s pension in the amount of $1,640. See “—Other Benefits and Perquisites” above for more information. In accordance with applicable SEC rules and requirements, we valued perquisites and personal benefits based on our incremental cost of providing such items.

Grants of Plan-Based Awards

None of our NEOs received grants of plan-based awards in 2023.

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Outstanding Equity Awards at Fiscal-Year End

The following table sets forth information concerning outstanding equity awards for our named executive officers as of the end of our fiscal year ended December 31, 2023. Messrs. Sabel and Pender did not hold any outstanding equity awards as of year-end.


Name	Grant Date⁽¹⁾		Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price ($)		Option Expiration Date
Jonathan Thayer		06/17/2020		4,375		625		5,200		06/17/2030
		05/12/2022		375		625		15,300		05/12/2032
Thomas Earl		07/18/2017		2,000		0		3,568		07/18/2027
		01/24/2018		1,000		0		3,771		01/24/2028
		04/01/2019		1,000		0		7,000		04/01/2029
		04/01/2020		875		125		5,200		04/01/2030
		04/20/2021		313		187		7,000		04/20/2031
		05/12/2022		375		625		15,300		05/12/2032
Keith Larson		07/01/2017		3,000		0		3,568		07/01/2027
		01/24/2018		1,000		0		3,771		01/24/2028
		04/01/2019		2,000		0		7,000		04/01/2029
		04/20/2021		313		187		7,000		04/20/2031
		05/12/2022		375		625		15,300		05/12/2032

(1)

All awards granted to our NEOs are options to purchase Series A common shares originally granted under the 2014 Plan which were converted, on a one-for-one basis, in connection with the Reorganization Transactions into options to purchase our Class A common shares under the 2023 Plan and remain outstanding under the 2023 Plan. All options granted to our NEOs vest in equal quarterly installments over a four-year period from the month of grant, subject to the NEO’s continued employment with us through each vesting date.

Option Exercises and Stock Vested

None of our NEOs exercised any stock options during our fiscal year ended December 31, 2023. We do not grant stock awards and, as such, so such awards vested in 2023.

Pension Benefits

None of our NEOs are entitled to any payments or other benefits following or in connection with retirement.

Nonqualified Deferred Compensation

None of our NEOs participate in any plan that provides for the deferral of compensation on a basis that is not tax-qualified.

Potential Payments Upon Termination or Change in Control

The Company does not maintain a formal severance policy, but certain of our NEOs have severance entitlements under the terms of their offer letters.Under Mr. Thayer’s offer letter, in the event his employment is terminated by us without “cause” (as defined in Mr. Thayer’s offer letter) or as a direct result of a “change in control” (which is defined to mean that both Messrs. Pender and Sabel cease to control the power to direct or cause the direction of the management or policies of VG LNG, whether through the ownership or voting

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securities, by agreement or otherwise), Mr. Thayer would be entitled to receive a lump sum severance payment equal to his then-current base salary, payable within 60 days of such termination, subject to his execution of a waiver and release agreement against the Company. Under Mr. Earl’s offer letter, we or Mr. Earl may terminate his employment at any time with not less than one week notice in writing. In the event Mr. Earl’s employment is terminated by us, we may make a payment in lieu of notice by providing an amount equal to then-current base salary for the remainder of the notice period.

None of our NEOs are entitled to any payments or benefits solely in the event of a change in control of our Company.

Assuming the termination of employment of Messrs. Thayer and Earl on December 31, 2023 under the circumstances described above, they would have received severance payments in the amount of (i) for Mr. Thayer, $1,500,000 and (ii) for Mr. Earl, $28,846 (assuming payment in lieu of one weeks’ notice of termination).

Prior to becoming a public company, we intend to enter into employment agreements with each of our NEOs which will provide for compensation and benefits, including severance protections, typical of those provided to executive officers of a public company, the terms of which will be described following entry into the agreements.

2023 Stock Option Plan

This section summarizes the key terms of the 2023 Plan as of the date of filing of this registration statement, which was adopted by our board of directors and approved by our shareholders in September 2023 in connection with the Reorganization Transactions. As of December 31, 2023, there were stock options outstanding under the 2023 Plan with respect to 67,796 shares of our Class A common stock having a weighted-average exercise price of $6,105.65 per share. In connection with this offering, it is expected that the outstanding stock options will be equitably adjusted pursuant to a stock split.

Purpose. The purpose of the 2023 Plan is to attract, reward and retain key service providers and to encourage their contribution to the long-term and growth and profitability of the Company.

Eligible Participants. Awards may be made to employees, consultants, service providers, non-employee directors and other individuals whose participation in the 2023 Plan is determined to be in the best interests of the Company.

Authorized Shares. The maximum number of shares available for issuance under the 2023 Plan is 95,000 shares of Class A common stock (which includes shares of Series A common stock to be issued pursuant to the exercise of options previously granted under the 2014 Plan), plus the shares underlying any awards that are not purchased or are forfeited or expire, or if an award otherwise terminates without delivery of any Class A common stock subject thereto or is settled in cash in lieu of shares. The share capacity will be increased by the number of shares underlying any awards the Company assumes in connection with a merger or other corporate transaction granted under an equity plan of another company. The 2023 Plan’s share capacity may be adjusted if the number of our outstanding common shares increases or decreases or if our common shares are otherwise changed or exchanged in connection with certain capital and corporate transaction.

Administration. The 2023 Plan is administered by a committee of our board of directors, or the Committee, or if no Committee is designated, the full board of directors. The Committee has the authority to determine eligible participants, the types of awards to be granted, the number of shares covered by awards and the terms and conditions of awards. The Committee may delegate some or all of its authority with respect to administering the 2023 Plan to our Chief Executive Officer and/or any other officer designated by the Committee, subject to the restrictions in the 2023 Plan.

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Award Agreement. Each award granted pursuant to the 2023 Plan will be evidenced by an award agreement which will be in such form or forms as the Committee determines.

Terms and Conditions of Options. The option price of each option will be fixed by the Committee and stated in the award agreement evidencing such option. Except in the case of substitute awards, the exercise price of each option must be at least the fair market value of a share of Class A common stock on the grant date; provided that in the event that a grantee is a 10% Company stockholder, the exercise price of any option intended to be an incentive stock option under Section 422 of the Code is not less than 110% of the fair market value of a share of Class A common stock on the grant date.

Only a grantee (or, in the event of such grantee’s legal incapacity or incompetency, such grantee’s guardian or legal representative) may exercise options granted under the 2023 Plan; provided, however, that if authorized in the applicable award agreement, a grantee may transfer, not for value, all or part of an option which is not an incentive stock option to any family member. Each award agreement will set forth the extent to which a grantee may exercise the granted options following his or her termination of employment.

Incentive Stock Options. The 2023 Plan authorizes the grant of incentive stock options under Section 422 of the Code, subject to those limits specified in the plan and by the Code.

Form of Payment for Options. To the extent provided by the applicable award agreement, the exercise price of options may be paid all or in part through the tender of shares of Class A common stock, which shall be valued at their fair market value on the date of tender.

To the extent permitted by applicable law and the applicable award agreement, an option’s exercise price may be paid all or in part by irrevocably directing a licensed securities broker to sell shares of Class A common stock and to deliver all or part of the proceeds of such sale to us as payment for the options’ exercise price and any withholding taxes, or, with our consent, by net share settlement (i.e., issuing the number of shares equal in value to the difference between the options’ exercise price and the fair market value of the shares subject to the portion of such option being exercised).

Forfeiture. The Committee may reserve the right in an award agreement to cause a forfeiture of the gain realized by a grantee with respect to an award on account of actions taken by, or failed to be taken by, such grantee in violation or breach of any agreement with, or obligation to, the Company.

No Repricing Without Stockholder Approval. Except in connection with certain corporate transactions, (a) the exercise price of an outstanding option may not be reduced; (b) an outstanding option may not be cancelled or substituted for an option with an exercise price that is less than the exercise price of the original options; or (c) options with an exercise price above the current Class A common stock price may not be cancelled in exchange for cash or other securities.

Change in Capitalization. If the number of outstanding Class A common shares is increased or decreased, or if the Class A common shares are exchanged for a different number or kind of securities, or in connection with specified capitalization transactions, the number and kinds of common shares underlying options granted pursuant to the 2023 Plan shall be adjusted proportionally by the Committee. Any such adjustment will not change the aggregate exercise price of an option award.

Termination of Service. Unless expressly provided otherwise in the applicable award agreement, vested stock options must be exercised within sixty days of an individual’s termination of service with the Company, at which point any unexercised options will be forfeited. The treatment described in this section does not apply to awards made to non-employee directors in their capacity as directors.

Change in Control. Upon a Change in Control (as defined in the 2023 Plan) in which outstanding options are not assumed or continued, the Committee may: (a) cause all options outstanding to be immediately

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exercisable beginning fifteen days prior to the scheduled consummation of such Change in Control, with such options to remain exercisable for a period of fifteen days, which exercise shall be effective upon such consummation; and/or (b) elect, in its sole discretion, to cancel any outstanding options and pay or deliver, or cause to be paid or delivered, to the holder thereof an amount in cash or securities with value equal to the number of shares subject to such options multiplied by the amount per share paid to holders of shares pursuant to such transaction exceeds the exercise price applicable to such options. In no event may any option be exercised, in whole or in part, after the occurrence of an event referred to with regard to a Change in Control which results in the termination of such option. Alternatively, option awards may be continued, assumed or substituted in connection with a Change in Control, with appropriate adjustments made to the number of shares underlying the awards and the exercise price.

Term; Amendment and Termination. The 2023 Plan terminates on December 16, 2024. The board of directors may at any time amend, suspend or terminate the 2023 Plan as to any shares as to which awards have not been made. No amendment, suspension or termination of the 2023 Plan may impair the rights or obligations of any award granted thereunder without the grantee’s consent. We do not expect to make grants under the 2023 Plan following the consummation of the IPO. In connection with this offering, we intend to adopt a new omnibus incentive plan, under which our employees may receive long-term incentive compensation in the future.

Parachute Limitations. The 2023 Plan includes a “best net” provision. If a grantee is a disqualified individual (as defined in Section 280G(c) of the Code), any right of the grantee to any exercise, vesting, payment or benefit under the 2023 Plan should be reduced or eliminated (a) to the extent that any such right to exercise, vesting, payment, or benefit, taking into account all other rights, payments, or benefits to or for the grantee under the plan, would be considered a parachute payment under Section 280G(b)(2) of the Code, and (b) if as a result of receiving such parachute payment the aggregate after-tax amounts received by the grantee under the 2023 Plan and all other agreements and arrangements would be less than the maximum after-tax amount that could be received by the grantee without causing any such payment or benefit to be considered a parachute payment.

Withholding Taxes. We have the right to deduct from payments of any kind any federal, state or local taxes required by law to be withheld with respect to the vesting of or other lapse of restrictions applicable to an award or upon the issuance of any shares upon the exercise of an option. Subject to our prior approval, a grantee may elect to satisfy such withholding obligation, in whole or in part, (a) by causing us or an affiliate to withhold shares otherwise issuable to the grantee or (b) by delivering to us or such affiliate shares already owned by the grantee.

U.S. Federal Income Tax Consequences. A non-qualified stock option is an option that does not meet the requirements of Section 422 of the Code. A grantee will not recognize taxable income when granted a non-qualified stock option. When the grantee exercises the stock option, he or she will recognize taxable ordinary income equal to the excess of the fair market value of the shares received on the exercise date over the aggregate exercise price of the shares. The grantee’s tax basis in the shares acquired on exercise of the option will be increased by the amount of such taxable income. We generally will be entitled to a federal income tax deduction in an amount equal to the ordinary income that the grantee recognizes. When the grantee sells the shares acquired on exercise, the grantee will realize long-term or short-term capital gain or loss, depending on whether the grantee holds the shares for more than one year before selling them. Special rules apply if all or a portion of the exercise price is paid in the form of shares.

An incentive stock option is an option that meets the requirements of Section 422 of the Code. A grantee will not have taxable income when granted an incentive stock option or when exercising the option. If the grantee exercises the option and does not dispose of the shares until the later of two years after the grant date and one year after the exercise date, the entire gain, if any, realized when the grantee sells the shares will be taxable as long-term capital gain. We will not be entitled to any corresponding tax deduction.

If a grantee disposes of the shares received upon exercise of an incentive stock option within the one-year or two-year periods described above, it will be considered a “disqualifying disposition,” and the option will be

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treated as a non-qualified stock option for federal income tax purposes. If a grantee exercises an incentive stock option more than three months after the grantee’s employment or service with us terminates, the option will be treated as a non-qualified stock option for federal income tax purposes. If the grantee is disabled and terminates employment or service because of his or her disability, the three-month period is extended to one year. The three-month period does not apply in the case of the grantee’s death.

Director Compensation

The following table sets forth information concerning the compensation earned by each of our non-employee directors during the fiscal year ended December 31, 2023.


Name⁽¹⁾	Fees Earned or Paid in Cash ($)		Option Awards ($)⁽³⁾		Total ($)
Roderick Christie⁽²⁾	$	180,000	$	4,097,061	$	4,277,061
Sari Granat	$	220,000		—	$	220,000
Andrew Orekar	$	220,000		—	$	220,000
Thomas J. Reid	$	200,000		—	$	200,000
Jimmy Staton	$	220,000		—	$	220,000

(1)	Roderick Christie was appointed to our board of directors on June 1, 2023.

(2)

Meeting fees reported with respect to Mr. Christie were earned in U.S. dollars and paid in British pounds using exchange ratios of 0.7871, 0.8030 and 0.7942, which represent the Oanda exchange rates in effect as of June 16, 2023, September 15, 2023 and December 7, 2023, the dates of the applicable board meetings for which such fees were earned and paid.

(3)

The amounts reported in this column represent the aggregate grant date fair value of the option awards granted to our non-employee directors during 2023, as calculated in accordance with FASB Accounting Standards Codification Topic 718. The assumptions used in calculating the grant date fair value of the options in this column are described in Note 19 to our consolidated financial statements included elsewhere in this prospectus. The aggregate number of option awards outstanding for each of our non-employee directors as of December 31, 2023 was: Mr. Christie, 500 options; Ms. Granat, 500 options; Mr. Orekar, 500 options; Mr. Reid, 500 options; and Mr. Staton, 4,416 options (2,916 of which were awarded in connection with Mr. Staton’s service as an employee of the Company).

We currently do not maintain a director compensation program or policy in which our non-employee directors participate. Rather, under our current director compensation arrangements, each of our non-employee directors receives a fee of $60,000 (increased from $20,000 effective as of June 1, 2023) payable in cash for each regular and special board of directors meeting attended, whether in person or by telephone. In addition, each of our non-employee directors receives a grant of stock options in connection with their appointment to our board of directors, which options vest in equal quarterly installments over a four-year period from the grant date, subject to their continued service through each vesting date (other than the 2,916 options awarded to Mr. Staton in connection with his service as an employee of the Company, which vest in equal quarterly installments over a three-year period). Our non-employee directors are reimbursed for their reasonable expenses incurred in attending meetings of the board of directors or committees. Employee directors do not receive additional compensation for their service on the board of directors.

In connection with this offering, we intend to adopt a director compensation program which will govern the annual compensation paid to our non-employee directors.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We describe below transactions and series of similar transactions, during our last three fiscal years or currently proposed, to which we were a party or will be a party, in which:

•

the amounts involved exceeded or will exceed $120,000; and

•

any of our directors, executive officers or beneficial holders of more than 5% of any class of our capital stock had or will have a direct or indirect material interest.

Other than as described below, there have not been, nor are there any currently proposed, transactions or series of similar transactions meeting this criteria to which we have been or will be a party other than compensation arrangements, which are described where required under “Management—Board Structure and Compensation of Directors” and “Executive Compensation.”

Reorganization Transactions

In connection with certain reorganization transactions, or the Reorganization Transactions, Legacy VG Partners, the Company and certain entities affiliated with Pacific Investment Management Company, or PIMCO, holding VGLNG’s Series C common stock entered into a transaction agreement on September 25, 2023, or the Transaction Agreement. Pursuant to the Transaction Agreement, the Company issued 78,464 shares of Class A common stock to PIMCO, in exchange for all of PIMCO’s outstanding 78,464 shares of Series C common stock in VGLNG. In addition, Legacy VG Partners agreed to merge with and into the Company, with VG Partners receiving 435,499 shares of Class A common stock in the Company in exchange for its equity interests in Legacy VG Partners. Moreover, VG Partners received one Class A common in the Company stock in exchange for its one share of Series A common stock of VGLNG.

In addition, in connection with the Reorganization Transactions, the remaining shareholders of VGLNG, which consisted of certain shareholders holding 5,808 shares of VGLNG’s Class C common shares that were not party to the Transaction Agreement, received 5,808 Class A common stock of the Company in exchange for such Series C common shares.

As a result, VGLNG, our principal operating company, became a direct, wholly-owned subsidiary of the Company. Additionally, VG Commodities, formerly a wholly-owned subsidiary of Legacy VG Partners, became a wholly-owned subsidiary of the Company and a direct, wholly owned subsidiary of VGLNG. After giving effect to the Reorganization Transactions, VG Partners, the controlling shareholder of the Company, owns approximately 84% of the issued and outstanding shares of Class A common stock, which shares automatically convert into shares of Class B common stock of the Company, which have 10 votes per Class B common stock, immediately prior to the consummation of the first underwritten initial public offering of Class A common stock, so long as such shares are held by VG Partners, its affiliates or other related parties at such time.

Existing Shareholders’ Agreement

In connection with the Reorganization Transactions, the Company and all of the holders of its outstanding common stock immediately prior to consummation of the offering, or, collectively, the Pre-IPO Stockholders, entered into the Shareholders’ Agreement, dated as of September 25, 2023, or the Existing Shareholders’ Agreement, governing the ownership of the shares of the Company. The Existing Shareholders’ Agreement contains certain consent rights for certain actions or decisions as well as registration rights and tag-along rights with respect to certain offerings and dispositions of stock of the Company.

Effective upon the consummation of this offering, all provisions of the Existing Shareholders’ Agreement will automatically terminate, except for certain registration rights, which will be reflected in an amended and restated version of the Existing Shareholders’ Agreement, or the Amended and Restated Shareholders’ Agreement.

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Amended and Restated Shareholders’ Agreement

Pursuant to the Amended and Restated Shareholders’ Agreement, our Pre-IPO Stockholders will be entitled to certain demand and piggyback registration rights with respect to their shares of our common stock. The Pre-IPO Stockholders will hold an aggregate of shares of our Class A common stock and shares of our Class B common stock, or approximately % of the total combined voting power of our common stock outstanding upon the completion of this offering (or % if the underwriters exercise their option to purchase additional shares from us in full). The registration rights described below will terminate with respect to any registrable securities upon the occurrence of certain events, including if sold pursuant to Rule 144 promulgated under the Securities Act or an effective registration statement under the Securities Act, or if such registrable securities are eligible to be sold under Rule 144 promulgated under the Securities Act and the Pre-IPO Stockholders no longer beneficially own in the aggregate common stock equal to at least 10% of our then outstanding common stock, in each case subject to certain conditions. Upon transfer of any shares of registrable securities to any person (other than an affiliate of the transferee) in accordance with the terms of the Amended and Restated Shareholders’ Agreement, such shares will cease to be “registrable securities” and will no longer have the benefit of the Amended and Restated Shareholders’ Agreement.

Piggyback Registration Rights. In the event that we register any of our equity securities under the Securities Act and VG Partners proposes to include any of its registrable securities in the registration statement, the Pre-IPO Stockholders will be entitled to certain piggyback registration rights allowing each to include its shares of Class A common stock in the registration, subject to certain marketing and other limitations. If any managing underwriter advises that marketing factors require a limitation of the number of shares to be included in any registration, then the number of shares to be included in such registration will be allocated pro rata based on the number of shares requested to be included in the registration by the initiating security holders and any such Pre-IPO Stockholders exercising piggyback registration rights. As a result, whenever we propose to file a registration statement under the Securities Act for the account of any of our security holders under the Amended and Restated Shareholders’ Agreement, Pre-IPO Stockholders will be entitled to notice of the registration.

Demand Registration Rights. At any time beginning 180 days after the completion of this offering, any Pre-IPO Stockholders holding at least 5% of our then outstanding common stock may request that we register, either by filing a Form S-1 registration statement or, if eligible, a Form S-3 registration statement, all or a portion of their Class A common stock. Any such request must cover a quantity of shares with an anticipated aggregate offering price, net of underwriting discounts and commissions, of at least $100.0 million. To the extent applicable, any of the Pre-IPO Stockholders holding at least 5% of our then outstanding common stock may then request an underwritten offering or block trade using any existing and effective shelf registration statement, in each case subject to certain conditions. Depending on certain conditions, we may defer a demand registration for up to 120 days after receiving the request of the initiating holders; provided that we may not invoke this right more than twice in any twelve-month period. The Pre-IPO Stockholders agree, pursuant to contractual lock-ups, to not exercise any of their rights under the Amended and Restated Shareholders’ Agreement for days, as described under “Underwriting.”

Expenses; Indemnification. The registration rights of the Pre-IPO Stockholders under the Amended and Restated Shareholders’ Agreement will provide that we must pay all registration expenses (other than the underwriting discounts and commissions) in connection with effecting any demand registration or shelf registration, and contains customary indemnification and contribution provisions.

Management Services Agreements

VGLNG Management Services Agreement

VGLNG entered into a management services agreement with Legacy VG Partners on June 27, 2014, which we subsequently amended and restated in December 2014 and April 2015, or, as amended, the VGLNG Management Services Agreement. In connection with the Reorganization Transactions, Legacy VG Partners was

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merged with and into the Company and the VGLNG Management Services Agreement was assigned from Legacy VG Partners to VG Partners, effective as of September 25, 2023.

Pursuant to the VGLNG Management Services Agreement, VG Partners is required to provide strategic advice in the form of such management services to VGLNG as VGLNG may request from time to time with respect to the Calcasieu Project, the Plaquemines Project and any other LNG facilities that VGLNG develops. The term of the VGLNG Management Services Agreement commenced on December 1, 2014, and continues until the later of either (i) the expiration of the useful life of all of the LNG projects that VGLNG develops, or (ii) 25 years after COD of the last LNG project VGLNG develops that achieves commercial operations, subject to extension thereafter.

Since August 2019, VGLNG has been required to pay Legacy VG Partners or VG Partners, as applicable, a fee for its availability to perform the services pursuant to the VGLNG Management Services Agreement . Such fee is $500,000 per month (increased annually for inflation based on the consumer price index). Pursuant to the VGLNG Management Services Agreement, VGLNG incurred fees payable to Legacy VG Partners of $6.4 million and $6.1 million, for the years ended December 31, 2022 and 2021, respectively. For the year ended December 31, 2023, VGLNG incurred fees payable to Legacy VG Partners of $5 million, and fees payable to VG Partners of $2 million under such agreement.

Venture Global Management Services Agreement

VG Commodities entered into a management services agreement, or the Venture Global Management Services Agreement, with Legacy VG Partners on December 1, 2014. In connection with the Reorganization Transactions, the Venture Global Management Services Agreement was assigned from Legacy VG Partners to VG Partners and from VG Commodities to the Company, effective as of September 25, 2023.

Pursuant to the Venture Global Management Services Agreement, VG Partners is required to provide strategic advice in the form of such management services to us as we may request from time to time, including with respect to the optimization of the purchase and sale of excess capacity from VGLNG’s projects and related agreements. The term of the Venture Global Management Services Agreement commenced on December 1, 2014, and continues until the later of either (i) the expiration of the useful life of all of the LNG projects that VGLNG develops, or (ii) 25 years after COD of the last LNG project VGLNG develops that achieves commercial operations, subject to extension thereafter. Upon the occurrence of the Calcasieu Project’s COD, we will be required to pay VG Partners $500,000 per month (increased annually for inflation based on the consumer price index) pursuant to the VGLNG Management Services Agreement.

As of December 31, 2023, no fees have been paid under the Venture Global Management Services Agreement.

Limitation of Liability and Indemnification of Directors and Officers

Our amended and restated certificate of incorporation and our amended and restated bylaws, both of which will become effective immediately prior to the completion of this offering, will contain provisions that limit the liability of our directors or officers for monetary damages to the fullest extent permitted by Delaware law. See “Description of Capital Stock—Limitation of Liability and Indemnification of Directors and Officers.”

Further, prior to the completion of this offering, we expect to enter into indemnification agreements with each of our directors and officers that may be broader than the specific indemnification provisions contained in the DGCL. These indemnification agreements will require us, among other things, to indemnify our directors and officers against liabilities that may arise by reason of their status or service. These indemnification agreements will also require us to advance all expenses incurred by the directors and officers in investigating or defending any such action, suit, or proceeding. We believe that these charter and bylaw provisions and indemnification agreements are necessary to attract and retain qualified individuals to serve as directors and officers.

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Policies and Procedures for Related Person Transactions

Our board of directors intends to adopt a written related person transaction policy, to be effective upon the closing of this offering, setting forth the policies and procedures for the review and approval or ratification of related person transactions. This policy will cover, with certain exceptions set forth in Item 404 of Regulation S-K under the Securities Act, any transaction, arrangement or relationship, or any series of similar transactions, arrangements or relationships, in which we were or are to be a participant, where the amount involved exceeds $120,000 in any fiscal year and a related person had, has or will have a direct or indirect material interest, including without limitation, purchases of goods or services by or from the related person or entities in which the related person has a material interest, indebtedness, guarantees of indebtedness and employment by us of a related person. In reviewing and approving any such transactions, we consider all relevant facts and circumstances, including, but not limited to, whether the transaction is on terms comparable to those that could be obtained in an arm’s length transaction and the extent of the related person’s interest in the transaction. All of the transactions described in this section occurred prior to the adoption of this policy. However, the policy will apply to new agreements, amendments and modifications to existing agreements, terminations, disputes and extensions, in each case involving amounts in excess of $120,000.

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PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding beneficial ownership of our common stock as of , 2024 by:

•

each person, or group of affiliated persons, known by us to beneficially own more than 5% of our common stock;

•

each of the directors and named executive officers individually; and

•

all directors and executive officers as a group.

In accordance with the rules of the SEC, beneficial ownership includes voting or investment power with respect to securities and includes the shares issuable pursuant to stock options that are exercisable within 60 days of . Shares issuable pursuant to stock options are deemed outstanding for computing the percentage of the person holding such options but are not outstanding for computing the percentage of any other person.

The number of shares of Class A common stock outstanding after this offering includes shares of Class A common stock being offered for sale by us in this offering. Percentage computations are based on shares of our Class A common stock and no shares of our Class B common stock outstanding as of , 2024, and shares of our Class A common stock and shares of our Class B common stock outstanding following this offering (assuming no exercise of the underwriters’ option to purchase additional shares).

Unless otherwise indicated, the address for each listed stockholder is: c/o Venture Global, Inc., 1001 19th Street North, Suite 1500, Arlington, VA, 22209. To our knowledge, except as indicated in the footnotes to this table and pursuant to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all shares of common stock.

Class A Shares
Beneficially
Owned Before
the Offering

% of
Total
Voting
Power
Before
Offering
(1)

Shares
Offered
Hereby

Class A Shares
Beneficially
Owned After the
Offering
Assuming the
Underwriters’
Option Is Not
Exercised(1)

% of
Total
Voting
Power
After
Offering
(1)

Class A Shares
Beneficially
Owned After the
Offering
Assuming
Exercise of
Underwriters’
Option

Name and Address of Beneficial
Owner

Shares

Percent

Shares

Percent

Shares

Percent

5% Stockholders

Venture Global Partners II, LLC⁽²⁾

Directors and Named Executive Officers:

Michael Sabel

Robert Pender

Sari Granat

Andrew Orekar

Thomas J. Reid

Jimmy Staton

Roderick Christie

Jonathan Thayer

Keith Larson

Thomas Earl

All directors and executive officers as a group (12 persons)

*	Represents less than 1%.

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(1)

Percentage of total voting power represents voting power with respect to all shares of our Class A common stock and Class B common stock, as a single class. The holders of our Class B common stock are entitled to ten votes per share, and holders of our Class A common stock are entitled to one vote per share. For more information about the voting rights of our Class A and Class B common stock, see “Description of Capital Stock—Common Stock.”

(2)

Robert Pender and Michael Sabel are co-managing members of Venture Global Partners II, LLC, and as such, are deemed to have voting and dispositive power over the common stock held by Venture Global Partners II, LLC. The address for Venture Global Partners II, LLC is 1001 19th Street North, Suite 600, Arlington, VA 22209.

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DESCRIPTION OF CAPITAL STOCK

The following information reflects our amended and restated certificate of incorporation and amended and restated bylaws as these documents will be in effect upon the completion of this offering. The following descriptions are summaries of the material terms of these documents and relevant sections of the DGCL. Reference is made to the more detailed provisions of, and the descriptions are qualified in their entirety by reference to, these documents, copies of which are filed with the SEC as exhibits to the registration statement of which this prospectus is a part, and applicable law.

General

Following this offering, our authorized capital stock will consist of shares of Class A common stock, par value $0.01 per share, shares of Class B common stock, par value $0.01 per share, and shares of preferred stock, par value $0.01 per share.

Common Stock

Common stock outstanding

As of , 2024, there were shares of Class A common stock outstanding which were held of record by stockholders and no shares of Class B common stock outstanding. Immediately following consummation of this offering, there will be shares of Class A common stock outstanding and shares of Class B common stock outstanding, assuming no exercise of the underwriters’ option to purchase additional shares and no exercise of outstanding options and after giving effect to the sale of the shares of Class A common stock offered hereby and the conversion of all Class A common stock held by VG Partners (immediately prior to completion of this offering) into an equal number of shares of Class B common stock. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.

Except as otherwise expressly provided in our amended and restated certificate of incorporation or as required by applicable law and as described herein, our Class A common stock and Class B common stock have the same rights, are equal in all respects and are treated by us as if they were the same.

Voting rights

Shares of our Class A common stock are entitled to one vote per share and shares of our Class B common stock are entitled to ten votes per share. Our shares of Class B common stock will convert automatically into one fully paid and nonassessable share of Class A common stock upon any transfer of such share, except for certain permitted transfers described in our amended and restated certificate of incorporation. See “—Conversion, Exchange and Transferability.” Holders of shares of Class A common stock and Class B common stock will vote together as a single class on all matters (including the election of directors) submitted to a vote of stockholders, except as otherwise required by applicable law or as set forth in our amended and restated certificate of incorporation.

Conversion, Exchange and Transferability

Shares of Class A common stock are not convertible into any other class of shares.

Each outstanding share of Class B common stock may at any time, at the option of the holder, be converted into one fully paid and nonassessable share of Class A common stock. In addition, each outstanding share of Class B common stock will be automatically converted into one share of Class A common stock upon any transfer of such share of Class B common stock, except for certain permitted transfers described in our amended and restated certificate of incorporation. Permitted transferees include VG Partners, its affiliates and beneficial owners and their beneficial owners’ immediate family members and estate planning vehicles.

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Other than as described above, our Class B common stock will not be converted into Class A common stock.

Dividend rights

Subject to preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available therefor. See “Dividend Policy.”

We will not declare or pay any dividend or make any distribution to the holders of Class A common stock or Class B common stock payable in securities of the Company unless the same dividend or distribution with the same record date and payment date shall be declared and paid on all shares of our common stock (unless different treatment of the shares of each such class is approved by the affirmative vote of the holders of a majority of the outstanding shares of the applicable class of common stock treated adversely, voting separately as a class); provided, however, that (i) dividends or other distributions payable in shares of Class A common stock or rights to acquire shares of Class A common stock may be declared and paid to the holders of Class A common stock without the same dividend or distribution being declared and paid to the holders of the Class B common stock if, and only if, a dividend payable in shares of Class B common stock, or rights to acquire shares of Class B common stock, as applicable, are declared and paid to the holders of Class B common stock at the same rate and with the same record date and payment date; and (ii) dividends or other distributions payable in shares of Class B common stock or rights to acquire shares of Class B common stock may be declared and paid to the holders of Class B common stock without the same dividend or distribution being declared and paid to the holders of the Class A common stock if, and only if, a dividend payable in shares of Class A common stock, or rights to acquire shares of Class A common stock, as applicable, are declared and paid to the holders of Class A common stock at the same rate and with the same record date and payment date (and provided that any dividend or other distribution paid in accordance with this proviso shall not require any other approval as set forth in our amended and restated certificate of incorporation).

Rights upon liquidation

In the event of our liquidation, dissolution or winding up, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock, if any, then outstanding.

Other rights

Other than as described above, holders of our common stock have no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock.

Registration Rights

Under the Amended and Restated Shareholders’ Agreement, the holders of shares of common stock will have the right to require us to register the offer and sale of their shares, which we refer to as registration rights. See “Certain Relationships and Related Party Transactions—Amended and Restated Shareholders’ Agreement.”

Preferred Stock

Our board of directors has the authority to issue the preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, dividend rates, conversion rights, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of such series, without further vote or action by the stockholders.

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The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control of us without further action by the stockholders and may adversely affect the voting and other rights of the holders of common stock. At present, we have no plans to issue any of the preferred stock.

Annual Stockholders Meeting

Our amended and restated certificate of incorporation provides that the annual meeting of stockholders shall be held in the manner designated by the board of directors each year, at which meeting, directors shall be elected and any other proper business may be transacted.

Election and Removal of Directors

Our board of directors will consist of between and directors. The exact number of directors will be fixed from time to time by resolution of the board, or in the manner provided for in our amended and restated bylaws. Any vacancy occurring on the board of directors and any newly created directorship may be filled only by a majority of the remaining directors in office, even if less than a quorum, by a sole remaining director or by the shareholders; provided that if VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, any vacancy occurring on the board of directors and any newly created directorship may only be filled by a majority of the directors then in office, even if less than a quorum, or by a sole remaining director (and not by the shareholders).

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, no director may be removed except for cause, and directors may be removed for cause by an affirmative vote of shares representing a majority of the shares then entitled to vote at an election of directors.

While VG Partners beneficially owns, in the aggregate, more than 50% of the total combined voting power or we qualify as a “controlled company” under the rules, directors may be removed with or without cause by an affirmative vote of shares representing a majority of the shares then entitled to vote at an election of directors.

Anti-Takeover Effects of our Certificate of Incorporation and By-laws

Some provisions of our amended and restated certificate of incorporation and bylaws are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection give us the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us, and that the benefits of this increased protection outweigh the disadvantages of discouraging those proposals, because negotiation of those proposals could result in an improvement of their terms.

Classified Board of Directors

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three-year terms, other than directors who may be elected by holders of preferred stock, if any. The classification of our board of directors into three classes could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors. While VG Partners beneficially owns, in the aggregate, more than 50% of the outstanding shares of our total combined voting power or we qualify as a “controlled company” under the

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rules, our board of directors will consist of a single class of directors serving one-year terms. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired.

Limits on Written Consents

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, our amended and restated certificate of incorporation and our amended and restated bylaws will provide that holders of our common stock will not be able to act by written consent without a meeting, unless such consent is unanimous. Prior to such time, shareholder actions may be taken by written consent without a meeting.

Stockholder Meetings

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, our amended and restated certificate of incorporation and our amended and restated bylaws will provide that special meetings of our stockholders may be called only by a chairman or co-chairman of our board of directors or a majority of the directors, and by no other person. Prior to such time, a special meeting of stockholders may be called by stockholders holding a majority of the outstanding shares entitled to vote.

Amendment of Certificate of Incorporation

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or after we fail to qualify as a “controlled company” under the rules, the provisions of our amended and restated certificate of incorporation described under “—Election and Removal of Directors,” “—Amendment of Bylaws,” “—Limits on Written Consents,” “—Stockholder Meetings” and “—Amendment of Certificate of Incorporation” may be amended only by the affirmative vote of holders of at least 75% of the total combined voting power of our shares of voting stock, voting together as a single class. The affirmative vote of holders of at least a majority of the voting power of our outstanding shares of stock will generally be required to amend other provisions of our amended and restated certificate of incorporation.

While VG Partners beneficially owns, in the aggregate, more than 50% of the total combined voting power or we qualify as a “controlled company” under the rules, our amended and restated certificate of incorporation may be amended by the affirmative vote of shares representing a majority of the shares then entitled to vote.

Amendment of Bylaws

At any time after VG Partners no longer beneficially owns, in the aggregate, more than 50% of the total combined voting power of our common stock or we fail to qualify as a “controlled company” under the rules, our amended and restated bylaws may generally be altered, amended or repealed, and new bylaws may be adopted, with:

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the affirmative vote of a majority of directors present at any regular or special meeting of the board of directors called for that purpose, provided that any alteration, amendment or repeal of, or adoption of any bylaw inconsistent with, specified provisions of the bylaws (including those related to special and annual meetings of stockholders, action of stockholders by written consent, classification of the board of directors, nomination of directors, special meetings of directors, removal of directors, committees of the board of directors and indemnification of directors and officers) requires the affirmative vote of at least 75% of all directors at a meeting called for that purpose; or

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the affirmative vote of holders of 75% of the total combined voting power of our outstanding share of voting stock, voting together as a single class.

While VG Partners beneficially owns, in the aggregate, more than 50% of the total combined voting power or we qualify as a “controlled company” under the rules, our amended and restated bylaws may be amended by either the affirmative vote of a majority of directors present at any regular or special meeting of the board of directors called for that purpose, or the affirmative vote of shares representing a majority of the shares then entitled to vote.

Stockholders Advance Notice Procedures

Our amended and restated bylaws will also impose some advance notice procedural and information requirements on stockholders who wish to:

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make nominations in the election of directors;

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propose that a director be removed;

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propose any repeal or change in our bylaws; or

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propose any other business to be brought before an annual or special meeting of stockholders.

Under these procedural requirements, in order to bring a proposal before a meeting of stockholders, a stockholder must deliver timely notice of a proposal pertaining to a proper subject for presentation at the meeting to our corporate secretary along with the following:

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a description of the business or nomination to be brought before the meeting and the reasons for conducting such business at the meeting;

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the stockholder’s name and address;

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any material interest of the stockholder in the proposal;

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the number of shares beneficially owned by the stockholder and evidence of such ownership; and

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the names and addresses of all persons with whom the stockholder is acting in concert and a description of all arrangements and understandings with those persons, and the number of shares such persons beneficially own.

To be timely, a stockholder must generally deliver notice:

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in connection with an annual meeting of stockholders, not less than 120 nor more than 180 days prior to the first anniversary of the annual meeting of stockholders that was held in the immediately preceding year, but in the event that the date of the annual meeting is more than 30 days before or more than 60 days after the anniversary date of the preceding annual meeting of stockholders, a stockholder notice will be timely if received by us not later than the close of business on the later of (1) the 120th day prior to the annual meeting and (2) the 10th day following the day on which we first publicly announce the date of the annual meeting; or

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in connection with the election of a director at a special meeting of stockholders, not less than 40 nor more than 60 days prior to the date of the special meeting, but in the event that less than 55 days’ notice or prior public disclosure of the date of the special meeting of the stockholders is given or made to the stockholders, a stockholder notice will be timely if received by us not later than the close of business on the 10th day following the day on which a notice of the date of the special meeting was mailed to the stockholders or the public disclosure of that date was made.

In order to submit a nomination for our board of directors, a stockholder must also submit any information with respect to the nominee that we would be required to include in a proxy statement, as well as some other information. If a stockholder fails to follow the required procedures, the stockholder’s proposal or nominee will be ineligible and will not be voted on by our stockholders.

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Notwithstanding the foregoing, at any time when VG Partners beneficially owns, in the aggregate, at least 10% of the total combined voting power of our common stock, such advance notice procedure will not apply to VG Partners.

Delaware Anti-Takeover Law

We have expressly elected not to be governed by the “Business Combination” provisions of Section 203 of the DGCL. At any time after VG Partners no longer beneficially owns at least 25% of the total combined voting power of our outstanding common stock, such election shall automatically be withdrawn and we will thereafter be governed by the “Business Combination” provisions of Section 203 of the DGCL. Section 203 prevents an “interested stockholder,” which is defined generally as a person owning 15% or more of a corporation’s voting stock, or any affiliate or associate of that person, from engaging in a broad range of “business combinations” with the corporation for three years after becoming an interested stockholder unless:

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the board of directors of the corporation had previously approved either the business combination or the transaction that resulted in the stockholder’s becoming an interested stockholder;

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upon completion of the transaction that resulted in the stockholder’s becoming an interested stockholder, that person owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, other than statutorily excluded shares; or

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following the transaction in which that person became an interested stockholder, the business combination is approved by the board of directors of the corporation and holders of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.

Under Section 203, the restrictions described above also do not apply to specific business combinations proposed by an interested stockholder following the announcement or notification of designated extraordinary transactions involving the corporation and a person who had not been an interested stockholder during the previous three years or who became an interested stockholder with the approval of a majority of the corporation’s directors, if such extraordinary transaction is approved or not opposed by a majority of the directors who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors.

Section 203 may make it more difficult for a person who would be an interested stockholder to effect various business combinations with a corporation for a three-year period. Section 203 also may have the effect of preventing changes in our management and could make it more difficult to accomplish transactions which our stockholders may otherwise deem to be in their best interests.

Limitation of Liability and Indemnification of Directors and Officers

Our amended and restated certificate of incorporation will provide that no director or officer will be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director or officer, except as required by applicable Delaware law, as in effect from time to time. Currently, Delaware law requires that liability be imposed for the following:

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any breach of the director’s or officer’s duty of loyalty to us or our stockholders;

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any act or omission of a director or officer not in good faith or which involved intentional misconduct or a knowing violation of law;

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with respect to a director, unlawful payment of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the DGCL;

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any transaction from which the director derived an improper personal benefit; and

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with respect to an officer, any action by or in our right.

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As a result, neither we nor our stockholders have the right, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.

Our amended and restated certificate of incorporation will provide that, to the fullest extent permitted by Delaware law, we will indemnify our officers or directors against all damages, claims and liabilities arising out of the fact that the person is or was our director or officer, or served any other enterprise at our request as a director, officer, employee, agent or fiduciary. We will reimburse the expenses, including attorneys’ fees, incurred by a person indemnified by this provision when we receive an undertaking to repay such amounts if it is ultimately determined that the person is not entitled to be indemnified by us. Amending this provision will not reduce our indemnification obligations relating to actions taken before an amendment.

If Delaware law is amended to authorize corporate action further eliminating or limiting the personal liability of a director or officer, then the liability of our directors and officers will be eliminated or limited to the fullest extent permitted by Delaware law, as so amended. Our amended and restated certificate of incorporation does not eliminate a director’s or officer’s duty of care and, in appropriate circumstances, equitable remedies, such as injunctive or other forms of non-monetary relief, remain available under Delaware law. This provision also does not affect a director’s or officer’s responsibilities under any other laws, such as the federal securities laws or other state or federal laws. Our amended and restated bylaws will empower us to purchase insurance on behalf of any person whom we are required or permitted to indemnify.

Further, prior to the completion of this offering, we expect to enter into indemnification agreements with each member of our board of directors and our officers. These agreements will provide for the indemnification of our directors and officers for certain expenses and liabilities incurred in connection with any action, suit, proceeding, or alternative dispute resolution mechanism or hearing, inquiry, or investigation that may lead to the foregoing, to which they are a party, or are threatened to be made a party, by reason of the fact that they are or were a director, officer, employee, agent or fiduciary of us, or any of our subsidiaries, by reason of any action or inaction by them while serving as an officer, director, agent or fiduciary, or by reason of the fact that they were serving at our request as a director, officer, employee, agent, or fiduciary of another entity. In the case of an action or proceeding by or in the right of us or any of our subsidiaries, no indemnification will be provided for any claim where a court determines that the indemnified party is prohibited from receiving indemnification. We believe that these charter and bylaw provisions and indemnification agreements are necessary to attract and retain qualified persons as directors and officers.

The limitation of liability and indemnification provisions in our amended and restated certificate of incorporation and amended and restated bylaws may discourage stockholders from bringing a lawsuit against directors for breach of their fiduciary duties. They may also reduce the likelihood of derivative litigation against directors and officers, even though an action, if successful, might benefit us and our stockholders. Moreover, a stockholder’s investment may be harmed to the extent we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions. Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, or the Securities Act, may be permitted to our directors, officers, and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act, and is, therefore, unenforceable. There is no pending litigation or proceeding naming any of our directors or officers as to which indemnification is being sought, nor are we aware of any pending or threatened litigation that may result in claims for indemnification by any director or officer.

Corporate Opportunities

Delaware law permits corporations to adopt provisions renouncing any interest or expectancy in certain opportunities that are presented to the corporation or its officers, directors or stockholders. Under our amended and restated certificate of incorporation we will, to the fullest extent permitted from time to time by Delaware law, renounce any right, interest or expectancy in any business opportunity, or being offered an opportunity to

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participate in any business opportunity, that may from time to time be presented to the Pre-IPO Stockholders or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. No such person shall be liable to us for breach of any statutory, fiduciary, contractual or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director or officer.

Forum Selection

The Court of Chancery of the State of Delaware will be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, or (iv) any action asserting a claim governed by the internal affairs doctrine.

These provisions will not apply to suits brought to enforce a duty or liability created by the Securities Exchange Act of 1934, as amended, or the Exchange Act. Our amended and restated certificate of incorporation will further provide that the federal district courts of the United States of America will be 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. The exclusive forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers or stockholders, which may discourage lawsuits with respect to such claims. In addition, 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 our shares of capital stock shall be deemed to have notice of and consented to the foregoing forum selection provisions. See “Risk Factors—Risks Relating to this Offering and Ownership of Our Class A Common Stock—Our amended and restated certificate of incorporation will designate 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 could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or the Company’s directors, officers or other employees.”

Listing

We intend to apply to list our Class A common stock on under the symbol “VG.”

Transfer Agent and Registrar

The transfer agent and registrar for the Class A common stock is .

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DESCRIPTION OF INDEBTEDNESS AND PROJECT FINANCING

The following information is a summary of the material terms of agreements representing certain indebtedness of our subsidiaries. Reference is made to the more detailed provisions of, and the descriptions are qualified in their entirety by reference to, these documents, copies of which are filed with the SEC as exhibits to the registration statement of which this prospectus forms a part.

Project Debt Financing

Calcasieu Project

Calcasieu Pass Credit Facilities

On August 19, 2019, VGCP, as borrower and TCP, as obligor, entered into a senior secured first lien construction facility equal to $5,477 million, or the Construction/Term Facility, and a senior secured working capital facility equal to $300 million, which was subsequently upsized to $555 million, or, as upsized, the Working Capital Facility, and, together with the Construction/Term Facility, the Calcasieu Pass Credit Facilities, with Natixis, New York Branch, as credit facility agent, Mizuho Bank (USA), as collateral agent, and the lenders party thereto to fund the costs of developing, constructing and commissioning the Calcasieu Project. The Calcasieu Pass Credit Facilities have a final maturity date of August 19, 2026.

On August 5, 2021, VGCP prepaid approximately $2.1 billion of indebtedness outstanding under the Construction/Term Facility by using the proceeds from the offering of the VGCP 2029 Notes and the VGCP 2031 Notes described below and, on November 22, 2021, VGCP prepaid approximately $1.0 billion of indebtedness outstanding under the Construction/Term Facility by using the proceeds from the offering of the VGCP 2033 Notes described below, and on January 13, 2023, VGCP prepaid approximately $1.0 billion of indebtedness outstanding under the Construction/Term Facility by using the proceeds from the offering of the VGCP 2030 Notes, also described below.

During the years ended December 31, 2022 and 2021, VGCP drew $0.6 billion and $2.3 billion, respectively, under the Calcasieu Pass Credit Facilities. As of , 2024, December 31, 2023 and December 31, 2022, VGCP had $ billion, $1.2 billion and $2.3 billion, respectively, outstanding under the Construction/Term Facility. The Construction/Term Facility was fully drawn as of December 31, 2022. In addition, VGCP had $ million, $339 million and $553 million of outstanding letters of credit under the Working Capital Facility as of , 2024 December 31, 2023 and December 31, 2022, respectively, which reduced the available borrowing capacity under the Working Capital Facility by an equivalent amount.

In June 2023, we modified the Calcasieu Pass Credit Facility to transition its variable rate interest from LIBOR to SOFR. Borrowings under the Calcasieu Pass Credit Facilities bear interest at a set margin rate over the debt term, plus, at VGCP’s election, either a SOFR, plus a term SOFR adjustment, or base rate. The set margin rate for SOFR-based loans ranges from 2.38% to 2.88%. The set margin rate for base rate loans ranges from 1.38% to 1.88%. The term SOFR adjustment is either (i) 0.10% for a one-month term; (ii) 0.15% for a three-month term or (iii) 0.25% for a six-month term. VGCP can select a SOFR rate for a specific term of one month, three months, or six months in length, or a base rate that is the greatest of (i) the federal funds effective rate plus 0.50%, (ii) the bank prime rate, or (iii) one-month SOFR plus 1.10%. 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. VGCP also incurs quarterly commitment fees based on the undrawn commitment of the Calcasieu Pass Credit Facilities and certain letter of credit fees.

The principal of the loans made under the Construction/Term Facility must be repaid in quarterly installments. VGCP made the first of such amortization payments on March 31, 2023 and has continued to make quarterly payments as required under the Construction/Term Facility.

The Calcasieu Pass Credit Facilities also contain mandatory prepayment provisions that require prepayment upon certain asset dispositions, recovery events, issuances of debt and impairments of certain SPAs. VGCP may

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voluntarily prepay the Calcasieu Pass Credit Facilities on three business days’ notice without premium or penalty.

The Calcasieu Pass Credit Facilities contain customary affirmative and negative covenants, that, among other things, limit VGCP’s ability to incur additional indebtedness, undertake fundamental changes, create liens, make investments, dispose of assets, pay distributions or other restricted payments, or enter into new material project documents, or undertake certain actions under such material project documents. Additionally, VGCP must maintain a minimum historical debt service coverage ratio of 1.15:1 for the applicable period ending as of the end of any fiscal quarter, subject to limited exercises of equity cures.

The obligations of VGCP under the Construction/Term Facility are guaranteed by TCP and are secured by a first priority lien on substantially all of the assets of VGCP and TCP and by a pledge by Calcasieu Pass Pledgor, LLC, or CP Pledgor, of its limited liability company interests in VGCP and TCP, except that the real property rights held by TCP, including the rights of way related to the TransCameron Pipeline, are not encumbered by the security documents.

Calcasieu Common Terms Agreement

On August 19, 2019, VGCP and TCP entered into the Common Terms Agreement, or the Calcasieu Common Terms Agreement, with Natixis, New York Branch, as the facility agent for the lenders under the Calcasieu Pass Credit Facilities and Mizuho Bank, Ltd., as intercreditor agent, in order to set out certain provisions regarding, among other things: (a) common representations and warranties; (b) common covenants; and (c) common events of default under the documents including the agreement governing the Calcasieu Pass Credit Facilities. Future lenders under additional facility agreements may accede to the Calcasieu Common Terms Agreement.

Under the terms of the Calcasieu Common Terms Agreement, VGCP is required to hedge not less than 75%, but no more than 105%, of the variable interest rate exposure of its senior secured debt. VGCP is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of the Calcasieu Project, funding of a debt service reserve account equal to six months of debt service and achieving certain minimum historical and projected debt service coverage ratios of at least 1.25:1.00, provided that VGCP may make pre-completion distributions if it satisfies a number of conditions, including that the independent engineer has certified that it reasonably expects the Calcasieu Project completion date to be achieved by an agreed date certain (currently December 31, 2024, subject to certain extension) and that after giving effect to the distribution, VGCP and TCP will have sufficient funds to achieve the project completion date by such date certain.

Upon VGCP’s incurrence of any replacement debt, a portion of the Construction/Term Facility amounts outstanding and/or commitments in an amount equal to the amount of such replacement debt less certain provisions, costs, prepayment premiums, fees and expenses allowed pursuant to the Calcasieu Common Terms Agreement is required to be prepaid and/or cancelled, as the case may be.

The events of default set forth in the Calcasieu Common Terms Agreement constitute events of default under the Calcasieu Pass Credit Facilities. In the case of an uncured event of default (and after all applicable cure periods), the Calcasieu Pass Credit Facilities administrative agent may, or upon the direction of the required lenders under the Calcasieu Pass Credit Facilities must, accelerate all or any portion of the outstanding loans and other obligations due and payable under the Calcasieu Pass Credit Facilities or terminate all outstanding commitments thereunder. Such acceleration/termination is automatic following an event of default relating to bankruptcy/insolvency of VGCP, TCP, or CP Pledgor. Furthermore, if the Calcasieu Project does not commence commercial operation by the date certain noted above, an event of default under the Calcasieu Pass Credit Facilities will occur.

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Under the Calcasieu Common Terms Agreement, VGCP is required to comply with certain covenants in relation to its SPAs. Among other things, VGCP is required to maintain certain SPAs covering the Calcasieu Project, which provide for commitments to purchase a quantity of LNG that, in the aggregate, is at least equal to a base committed quantity of a certain mtpa for a period until the initial debt has been amortized and/or to replace such SPAs with SPAs with similar terms within 90 days of termination (subject to certain extension). VGCP must make a mandatory prepayment if (a) VGCP breaches the SPA maintenance covenant in the Calcasieu Common Terms Agreement or (b) with respect to any required SPA under the Calcasieu Common Terms Agreement, a required export authorization becomes impaired and VGCP does not provide a reasonable remediation plan within 30 days following such impairment, diligently pursue such remediation, and cause such remediation to be effective within 90 days following the occurrence of the impairment.

VGCP Senior Secured Notes

On August 5, 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 interest on 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.

On November 22, 2021, VGCP issued $1.25 billion aggregate principal amount of senior secured notes due 2033, or 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.

On January 13, 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.

VGCP’s obligations under the VGCP Senior Secured Notes are guaranteed by TCP and may be guaranteed by certain of VGCP’s future domestic subsidiaries, if any. The VGCP Senior Secured Notes and the guarantees are secured by certain collateral, or the VGCP Collateral, and the VGCP Senior Secured Notes and the Calcasieu Pass Credit Facilities share equally in such VGCP Collateral. The VGCP Senior Secured Notes are governed by the base indenture dated August 5, 2021, or the Base Indenture, as supplemented with respect to each particular series of notes. The Base Indenture contains customary terms and events of default and certain covenants that, among other things, limit or restrict VGCP’s ability and the ability of TCP and certain of VGCP’s future subsidiaries, if any, to (i) make restricted payments, (ii) incur additional indebtedness or issue preferred stock, (iii) guarantee the obligations of others, (iv) assume, incur, permit or suffer to exist liens on VGCP’s or their respective assets, (v) create or permit to exist or become effective any consensual encumbrance on the ability of a restricted subsidiary to pay dividends, pay indebtedness owed to VGCP, TCP or any of VGCP’s other restricted subsidiaries, make loans or advances to VGCP, TCP or VGCP’s other restricted subsidiaries, or sell, lease or transfer any properties or assets to VGCP, TCP or any of VGCP’s other restricted subsidiaries, (vi) consolidate, merge or sell substantially all of VGCP’s or their respective assets or properties, (vii) make investments, loans or advances, (viii) enter into certain transactions or agreements with or for the benefit of VGCP’s or their respective affiliates, (ix) amend or modify certain material project agreements or certain qualifying SPAs, (x) enter into hedging agreements, (xi) maintain accounts and (xii) create subsidiaries.

At any time or from time to time, prior to February 15, 2029, VGCP may redeem the VGCP 2029 Notes, in whole or in part, at a redemption price equal to 100% of the aggregate principal amount of the VGCP 2029 Notes, plus the “make-whole” set forth in the Base Indenture, plus accrued and unpaid interest up to but excluding the redemption date. In addition, at any time or from time to time, on or after February 15, 2029,

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VGCP may redeem the VGCP 2029 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the VGCP 2029 Notes to be redeemed, plus accrued and unpaid interest, if any, on the VGCP 2029 Notes redeemed up to but not including the redemption date.

At any time or from time to time, prior to February 15, 2031, VGCP may redeem the VGCP 2031 Notes, in whole or in part, at a redemption price equal to 100% of the aggregate principal amount of the VGCP 2031 Notes, plus the “make-whole” set forth in the Base Indenture, plus accrued and unpaid interest up to but excluding the redemption date. In addition, at any time or from time to time, on or after February 15, 2031, VGCP may redeem the VGCP 2031 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the VGCP 2031 Notes to be redeemed, plus accrued and unpaid interest, if any, on the VGCP 2031 Notes redeemed up to but not including the redemption date.

At any time or from time to time, prior to May 1, 2033, VGCP may redeem the VGCP 2033 Notes, in whole or in part, at a redemption price equal to 100% of the aggregate principal amount of the VGCP 2033 Notes, plus the “make-whole” set forth in the first supplemental indenture to the Base Indenture, dated as of November 22, 2021, plus accrued and unpaid interest up to but excluding the redemption date. In addition, at any time or from time to time, on or after May 1, 2033, VGCP may redeem the VGCP 2033 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the VGCP 2033 Notes to be redeemed, plus accrued and unpaid interest, if any, on the VGCP 2033 Notes redeemed up to but not including the redemption date.

At any time or from time to time, prior to October 15, 2029, VGCP may redeem the 2030 notes, in whole or in part, at a redemption price equal to 100% of the aggregate principal amount of the VGCP 2030 Notes, plus the “make-whole” set forth in the second supplemental indenture to the Base Indenture, dated as of January 13, 2023, plus accrued and unpaid interest up to but excluding the redemption date. In addition, at any time or from time to time, on or after October 15, 2029, VGCP may redeem the VGCP 2030 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the VGCP 2030 Notes to be redeemed, plus accrued and unpaid interest, if any, on the VGCP 2030 Notes redeemed up to but not including the redemption date.

The VGCP Senior Secured Notes and the guarantees constitute VGCP’s and the guarantors’ direct and unconditional senior secured obligations and rank senior in right of payment to any of VGCP’s and the guarantors’ future indebtedness that is subordinated in right of payment to the VGCP Senior Secured Notes and the guarantees and are equal in right of payment with all of VGCP’s and the guarantors’ existing and future indebtedness that is not subordinated, including the Calcasieu Pass Credit Facilities. The VGCP Senior Secured Notes and the guarantees are effectively subordinated to all of VGCP’s and the guarantors’ indebtedness that is secured by assets, if any, other than the VGCP Collateral, to the extent of the value of such assets. The VGCP Senior Secured Notes and the guarantees are effectively senior to all of VGCP’s and the guarantors’ senior indebtedness that is unsecured to the extent of the value of the assets constituting the VGCP Collateral.

The VGCP Senior Secured Notes are not subject to the Calcasieu Common Terms Agreement.

As of , 2024, December 31, 2023 and December 31, 2022, the aggregate principal amount of VGCP Senior Secured Notes outstanding was $ , $4.8 billion and $3.8 billion, respectively.

Plaquemines Project

Plaquemines Credit Facilities

In May 2022, VGPL, as borrower, and Gator Express, as guarantor, 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) maturing on May 25, 2029, to fund the development and construction of Phase 1 of the Plaquemines Project. Proceeds from the Plaquemines Construction Term Loan are used to fund a portion of the costs of developing, constructing and commissioning the Plaquemines Project, and pay interest and associated debt transaction fees

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and expenses. The Plaquemines Working Capital Facility is used to secure letters of credit and provide working capital financing to VGPL. A portion of the proceeds from the project financing was used to prepay a bridge facility for the Plaquemines Project and pay fees and expenses incurred in connection with the project financing.

The project financing facilities were upsized in March 2023 to fund the development and construction of Phase 2 of the Plaquemines Project. The Plaquemines Credit Facilities are comprised of approximately $12.9 billion of the Plaquemines Construction Term Loan and $2.1 billion of the Plaquemines Working Capital Facility. The remaining proceeds from the upsized project financing will be used to fund the costs of financing, developing, constructing, and commissioning the Plaquemines Project.

As of , 2024, December 31, 2023 and December 31, 2022, VGPL had $ billion, $4.9 billion and $1.1 billion, respectively, outstanding, and $ billion, $8.0 billion and $7.4 billion, respectively, available, under the Plaquemines Construction Term Loan. VGPL had $ , $840 million and $253 million of outstanding letters of credit under the Plaquemines Working Capital facility as of , 2024, December 31, 2023 and December 31, 2022, respectively, which reduced the available borrowing capacity under the Plaquemines Working Capital Facility by an equivalent amount.

Borrowings under the Plaquemines Credit Facilities bear interest at either the SOFR or base rate, plus an applicable margin. VGPL can select a SOFR for a specific term of one month up to six months in length or a base rate that is the greatest of (i) the federal funds effective rate plus 0.50%, (ii) the bank prime rate, or (iii) the one-month term SOFR reference rate plus 1.10%. The set margin rate for SOFR-based loans ranges from 1.975% to 2.625%. The set margin rate for base rate loans ranges from 0.875% to 1.375%. Interest on term SOFR 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.

The principal on the loans made under the Plaquemines Construction Term Loan must be repaid in quarterly installments, beginning upon the earlier of the first calendar quarter end date occurring three months following completion of Phase 1 of the Plaquemines Project or February 28, 2027. The outstanding principal of the Plaquemines Credit Facilities may be repaid, in whole or in part, at any time without premium or penalty (subject to breakage fees).

The obligations of VGPL under the Plaquemines Credit Facilities are guaranteed by Gator Express and secured by a first-priority lien on substantially all of the assets of VGPL and Gator Express and by a pledge by Plaquemines LNG Pledgor, LLC, or Plaquemines Pledgor, of its limited liability company interests in VGPL and Gator Express, except that the real property rights held by Gator Express, including the rights of way related to Gator Express Pipeline, are not encumbered by the security documents.

Plaquemines Common Terms Agreement

On March 13, 2023, in connection with the upsize of the Plaquemines Credit Facilities, VGPL and Gator Express entered into the Amended and Restated Common Terms Agreement with Natixis, New York Branch, as the credit facility agent for the lenders under the Plaquemines Credit Facilities and Royal Bank of Canada, as intercreditor agent, or the Plaquemines Common Terms Agreement, in order to set out certain provisions regarding, among other things: (a) common representations and warranties; (b) common covenants; and (c) common events of default under the agreement governing the Plaquemines Credit Facilities. Currently, only the Plaquemines Credit Facilities are subject to the Common Terms Agreement. Future lenders under additional facility agreements may accede to the Plaquemines Common Terms Agreement.

Under the terms of the Plaquemines Common Terms Agreement, VGPL is required to hedge not less than 75% but no more than 105% of the variable interest rate exposure of its senior secured debt. VGPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of both phases of the Plaquemines Project, funding of a debt

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service reserve account equal to six months of debt service and achieving certain minimum historical and projected debt service coverage ratios of at least 1.25:1.00, provided that VGPL may make pre-completion distributions if it satisfies a number of conditions, including that the independent engineer has certified that it reasonably expects the completion date of Phase 1 and Phase 2 of the Plaquemines Project to be achieved by certain agreed deadlines and that after giving effect to the distribution, VGPL and Gator Express will have sufficient funds to achieve the project completion date by such deadlines.

Upon VGPL’s incurrence of any replacement debt, a portion of the amounts outstanding and/or commitments in an amount equal to the amount of such replacement debt less certain provisions, costs, prepayment premiums, fees and expenses allowed pursuant to the Plaquemines Common Terms Agreement is required to be prepaid and/or cancelled, as the case may be.

The events of default set forth in the Plaquemines Common Terms Agreement constitute events of default under the Plaquemines Credit Facilities. In the case of an uncured event of default (and after all applicable cure periods), the Plaquemines Credit Facilities administrative agent may, or upon the direction of the required lenders under the Plaquemines Credit Facilities must, accelerate all or any portion of the outstanding loans and other obligations due and payable under the Plaquemines Credit Facilities or terminate all outstanding commitments thereunder. Such acceleration/termination is automatic following an event of default relating to bankruptcy/insolvency of VGPL, Gator Express, or Plaquemines Pledgor. Furthermore, if the Plaquemines Project does not commence commercial operation by a specified date certain (currently February 28, 2027 and December 31, 2027, with respect to Phase 1 and Phase 2 of the Plaquemines Project, respectively, and, in each case, subject to extension in certain cases), an event of default under the Plaquemines Credit Facilities will occur.

Under the Plaquemines Common Terms Agreement, VGPL is required to comply with certain covenants relating to its SPAs. Among other things, VGPL is required to maintain certain SPAs covering the Plaquemines Project that provide for commitments to purchase a quantity of LNG that, in the aggregate, is at least equal to a base committed quantity of a certain mtpa for a period of no shorter than the lesser of (i) 12 years and (ii) the period until the debt has been amortized and/or to replace them with qualifying SPAs, which must provide for commitments to purchase LNG in quantities at least equal to the base committed quantity under the SPA being replaced, within 90 days of termination of the foundation SPA (subject to certain extension). VGPL must make a mandatory prepayment if (a) VGPL breaches the SPA maintenance covenant in the Plaquemines Common Terms Agreement or (b) with respect to any required SPA under the Plaquemines Common Terms Agreement, a required export authorization becomes impaired and VGPL does not provide a reasonable remediation plan within 30 days following such impairment, diligently pursue such remediation, and cause such remediation to be effective within 90 days following the occurrence of the impairment.

Project Equity Financing

Calcasieu Pass Holdings, LLC Preferred Units

On May 25, 2019, Calcasieu Holdings and a fund associated with Stonepeak Infrastructure Partners, or Stonepeak Fund I, entered into a unit purchase agreement where Calcasieu Holdings agreed to issue and sell to Stonepeak Fund I, and Stonepeak Fund I agreed to purchase, from Calcasieu Holdings 4,000,000 preferred units of Calcasieu Holdings, or Holdings Preferred Units, for an aggregate purchase price of $400 million, or the Holdings Face Value. The transaction closed on August 19, 2019, or the Equity Financing Closing Date. The terms of the Holdings Preferred Units are set forth in the limited liability company agreement of Calcasieu Holdings, dated as of August 19, 2019. Calcasieu Holdings applied the proceeds from the sale of the Holdings Preferred Units to fund the equity portion of the costs of developing, constructing and commissioning the Calcasieu Project and for other related business purposes of Calcasieu Holdings and its subsidiaries.

As of , 2024, we owned 100% of the outstanding Class A common units of Calcasieu Holdings, or Class A Common Units, Stonepeak Fund I owned 100% of the outstanding Holdings Preferred Units and there were no outstanding Class B common units of Calcasieu Holdings, or Class B Common Units.

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Ranking

The Holdings Preferred Units rank senior to all Class A Common Units and Class B Common Units of Calcasieu Holdings, or Holdings Common Units, and to each other class of units of Calcasieu Holdings established by the board of managers of Calcasieu Holdings, the terms of which do not expressly provide that it ranks senior to or pari passu with the Holdings Preferred Units.

Distributions on Holdings Preferred Units

Until the eighth anniversary of the Equity Financing Closing Date, each outstanding Holdings Preferred Unit will receive distributions in-kind in the form of additional Holdings Preferred Units, or Holdings PIK Units, at 10.0% per annum. From and after such eighth anniversary, the Holdings PIK Units will accrue at 10.0% per annum, plus an additional 0.50% for every six month period, but will not exceed 15.0% per annum. The Holdings PIK Units will be cumulative. Calcasieu Holdings has an option to pay any portion of such distributions in cash.

Distributions on Holdings Common Units

For each full month prior to the Holdings Conversion (as defined below), distributions on the Holdings Common Units must be paid from the net proceeds from the sale of commissioning cargos from the Calcasieu Project, on the monthly distribution date following such declaration by the board to the members holding Holdings Common Units. Following the Holdings Conversion, distributions on the Holdings Common Units must be paid from available cash at Calcasieu Holdings, net of certain payments on indebtedness and reserves, on a quarterly basis.

Conversion into Class B Common Units and Mandatory Redemption

Upon the earlier of (a) commencement of commercial operation of the Calcasieu Project or (b) both (i) the occurrence of a Liquidation Event (as defined below) (or certain merger, amalgamation or consolidation involving VGLNG, Calcasieu Holdings or Calcasieu Funding, or an initial public offering of Calcasieu Holdings or any of its subsidiaries that holders of Holdings Preferred Units elect to treat as a Liquidation Event, or an Elected Liquidation Event) and (ii) the election by Stonepeak Fund I to convert, all Holdings Preferred Units, including any Holdings PIK Units outstanding, will automatically be converted to Class B Common Units of Calcasieu Holdings, or the Holdings Conversion. If Stonepeak Fund I does not elect to convert the Holdings Preferred Units to Class B Common Units in connection with an Elected Liquidation Event, Calcasieu Holdings is required to redeem the Holdings Preferred Units at an agreed liquidation price. As of , 2024, the outstanding amount of the Holdings Preferred Units was approximately $ million. Assuming a commencement of commercial operations in 2024 and payment of certain distributions in cash, the Holdings Preferred Units are expected to convert into a number of Class B Common Units of Calcasieu Holdings equal to approximately % of the outstanding Holdings Common Units. As a result, after the conversion, we are expected to own 100% of the outstanding Class A Common Units, equal to approximately % of the outstanding Holdings Common Units, while Stonepeak Fund I is expected to own 100% of the outstanding Class B Common Units, equal to approximately % of the outstanding Holdings Common Units, and there will be no outstanding Holdings Preferred Units.

Approvals Required

Prior to the Holdings Conversion, holders of Holdings Preferred Units have the right to select and appoint one manager to the board of managers of Calcasieu Holdings (or when the Step-In Rights (as defined below) are exercised, two managers), and after the Holdings Conversion, holders of Class B Common Units shall have the same right. Such manager’s consent is required prior to Calcasieu Holdings or its subsidiaries taking the following actions, among others:

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amending key project contracts, including the Calcasieu EPC Contract, the engineering, procurement and construction agreement for the construction of the TransCameron Pipeline, and any of the

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Calcasieu Foundation SPAs, or, collectively, the Key Project Contracts, if such amendment could reasonably be expected to have an adverse effect in any material respect on Calcasieu Holdings and its subsidiaries, taken as a whole;

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incurring any additional indebtedness in excess of $75.0 million, except for refinancing of the debt financing described in “—Project Debt Financing—Calcasieu Project—Calcasieu Pass Credit Facilities”, debt incurred prior to commercial operation of the Calcasieu Project solely to fund construction and operation costs of the Calcasieu Project, a working capital facility or in connection with any additional or expansion LNG liquefaction project, in each case as specified under the limited liability company agreement of Calcasieu Holdings; and

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entering into any transaction with Calcasieu Funding (defined below), Stonepeak Fund I or any of their respective affiliates or any new contract or agreement with Venture Global LNG, Inc., Calcasieu Funding or any of their affiliates or amending any such existing contract, if the terms and conditions thereof are not commercially reasonable (from the perspective of Calcasieu Holdings and its subsidiaries) and are more favorable to Calcasieu Funding, Stonepeak Fund I or any of their respective affiliates than could be obtained on an arm’s length basis.

Step-In Right

If any of the following events occurs (subject to certain cure rights), then holders of Holdings Preferred Units (or holders of Class B Common Units after Holdings Conversion) will have the right to appoint two out of three managers to the board of managers of Calcasieu Holdings, or the Step-In Right, and members holding Class A Common Units will have the right to appoint one manager until and for so long as the circumstances that triggered such Step-In Right are continuing:

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an event of default under the Calcasieu Pass Credit Facilities or inability of VGCP to draw loans under the Calcasieu Pass Credit Facilities for a period of at least 60 consecutive days as a result of the failure to satisfy the conditions precedent therein;

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a material breach by Calcasieu Holdings or any of its subsidiaries under any of the Key Project Contracts that could, if uncured, result in termination of such Key Project Contract or the termination of any Key Project Contract;

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a material breach under the Funding LLC Agreement (defined below) that is adverse to the holders of Funding Preferred Units in a material respect;

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a significant casualty or condemnation event or loss of the DOE export license related to the Calcasieu Project or any other material permit, license, approval or authorization issued or granted by any governmental authority that results in the cessation of commercial operations of the Calcasieu Project in the ordinary course of business for at least 30 days;

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a delay in commencement of the commercial operations of the Calcasieu Project beyond 45 days prior to the date certain under the Calcasieu Common Terms Agreement;

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Accrued Distributions (as defined below) at Calcasieu Funding occurring for six consecutive calendar quarters commencing with the first full quarter following commencement of commercial operations at the Calcasieu Project;

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the aggregate amount of Accrued Distributions outstanding on the Funding Preferred Units following commencement of commercial operations at the Calcasieu Project exceeds 25.0% of the aggregate principal amount (including then outstanding Accrued Distributions) of the outstanding Funding Preferred Units as of the date on which the Calcasieu Project commences commercial operations; and

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Calcasieu Holdings not meeting the reasonable standard and expectation in operating the Calcasieu Project and as a result the annual aggregate liquefaction capacity of the Calcasieu Project being less than 75% of annual 10.0 mtpa aggregate nameplate capacity of the Calcasieu Project for three consecutive years following commencement of commercial operations of the Calcasieu Project, except to the extent caused by force majeure.

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In the event that the circumstances that triggered the Step-In Rights are no longer continuing, then members holding Class A Common Units will have the right to appoint two managers and members holding Holdings Preferred Units (or holders of Class B Common Units after Holdings Conversion) will have the right to appoint one manager of the board of managers of Calcasieu Holdings.

Liquidation Preference

In the event of any liquidation, dissolution or winding up of or bankruptcy, insolvency or other similar event in respect of Calcasieu Holdings, whether voluntary or involuntary, or Liquidation Event, a holder of Holdings Preferred Units will be entitled to be paid in cash, before any amount is paid or distributed to any holders of Holdings Common Units, an amount per Holdings Preferred Unit equal to the Holdings Face Value, as increased by the Holdings PIK Units and any accrued but unpaid distributions thereon.

Calcasieu Pass Funding, LLC Preferred Units

On May 25, 2019, Calcasieu Funding and a fund associated with Stonepeak Infrastructure Partners, or Stonepeak Fund II, entered into a unit purchase agreement where Calcasieu Funding agreed to issue and sell to Stonepeak Fund II and Stonepeak Fund II agreed to purchase from Calcasieu Funding 9,000,000 perpetual preferred units of Calcasieu Funding, or Funding Preferred Units for an aggregate purchase price of $900 million. The transaction closed on the Equity Financing Closing Date. The terms of the Funding Preferred Units are set forth in the limited liability company agreement of Calcasieu Funding, dated as of August 19, 2019, or the Funding LLC Agreement. Calcasieu Funding applied a portion of the proceeds from the sale of the Funding Preferred Units as a contribution to Calcasieu Holdings to be used by Calcasieu Holdings to fund the equity portion of the costs of developing, constructing and commissioning the Calcasieu Project.

As of , 2024, we owned 100% of the outstanding Common Units of Calcasieu Funding, or Funding Common Units, while Stonepeak Fund II owned 100% of the outstanding Funding Preferred Units.

Ranking

The Funding Preferred Units rank senior to all Funding Common Units and to each other class of units of Calcasieu Funding established by Calcasieu Holdings, as the managing member of Calcasieu Funding, or the Managing Member.

Distributions on Funding Preferred Units

Until the eighth anniversary of the Equity Financing Closing Date, each outstanding Funding Preferred Unit will receive distributions at 10.0% per annum either (i) from certain available cash at Calcasieu Funding, net of reserves and cash required for certain permitted tax distributions, or the Calcasieu Funding Available Amount, if so declared by the Managing Member or (ii) in the form of an increase in the Funding Face Value, or an Accrued Distribution, where the “Funding Face Value” is an initial value of $100 for each Funding Preferred Unit, as may be increased by Accrued Distributions as of the last day of each applicable quarter. From and after such eighth anniversary, the Funding Preferred Units will receive distributions, either in cash or in the form of Accrued Distribution, at 10.0% per annum, plus an additional 0.50% for every six month period, but will not exceed 15.0% per annum. After COD of the Calcasieu Project, the Accrued Distribution will be at a rate per annum equal to 1.0% per annum above the applicable distribution rate. The distributions are cumulative and the Accrued Distributions will increase the Funding Face Value of each Funding Preferred Unit. As of , 2024, the outstanding amount of the Funding Preferred Units was approximately $ billion.

Distributions on Funding Common Units

For each full month prior to COD of the Calcasieu Project, distributions on the Funding Common Units must be paid from the net proceeds from the sale of commissioning cargos from the Calcasieu Project, on the monthly distribution date determined by the Managing Member.

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Following COD of the Calcasieu Project, but prior to the eighth anniversary of the Equity Financing Closing Date, distributions on Funding Common Units must be paid from the Calcasieu Funding Available Amount on a quarterly basis on each quarterly distribution date determined by the Managing Member, but only for so long as at the time of any such distribution (i) Calcasieu Funding has redeemed for cash any Accrued Distributions that have previously cumulated and accrued and (ii) the requisite amount of distribution in cash on the Funding Preferred Units is made on such quarterly distribution date such that no Accrued Distribution is made or outstanding on such quarterly distribution date.

Following the eighth anniversary of the Equity Financing Closing Date but prior to the date on which all of the outstanding Funding Preferred Units have been redeemed in full, or the Redeemed in Full Date, except for certain permitted tax distributions by Calcasieu Funding, (i) no distributions on Funding Common Units may be declared or paid and (ii) Calcasieu Funding shall use all Calcasieu Funding Available Amount to effect Redemptions (as defined and described below under “—Optional Redemption”) as soon as reasonably practicable and in any event on each quarterly distribution date.

Following the Redeemed in Full Date, distributions on Funding Common Units must be paid from the Calcasieu Funding Available Amount on a quarterly basis.

Optional Redemption

At any time on or after the third anniversary of the Equity Financing Closing Date, Calcasieu Funding has the right to cause (and, to the extent required as described in “—Distributions on Funding Common Units,” Calcasieu Funding shall cause) all or any portion of the outstanding Funding Preferred Units (including Accrued Distributions) to be redeemed (each such redemption, a Redemption) for cash at the agreed redemption price per Funding Preferred Unit set forth below (such amount, the Redemption Price):

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if the date of Redemption is on or prior to the fourth anniversary of the Equity Financing Closing Date, an amount equal to the product of (a) 100% of the face value of such Funding Preferred Unit, as increased (without duplication, but including any accrual and any cumulation) by any Accrued Distributions, or the Base Return, multiplied by (b) 1.1;

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if the date of Redemption is after the fourth anniversary of the Equity Financing Closing Date and on or prior to the fifth anniversary of the Equity Financing Closing Date, an amount equal to the product of the Base Return multiplied by 1.05;

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if the date of Redemption is after the fifth anniversary of the Equity Financing Closing Date and on or prior to the sixth anniversary of the Equity Financing Closing Date, an amount equal to the product of the Base Return multiplied by 1.025; and

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if the date of Redemption is after the sixth anniversary of the Equity Financing Closing Date, an amount equal to the Base Return.

Restrictions on Issuances of Additional Equity

Other than Calcasieu Holdings contributing capital in exchange for issuance of common units in Calcasieu Funding, Calcasieu Funding may not issue, offer or sell additional units without a majority approval of holders of outstanding Funding Preferred Units.

Liquidation Preference

In the event of any liquidation, dissolution or winding up of or bankruptcy, insolvency or other similar event in respect of Calcasieu Funding, whether voluntary or involuntary, a holder of Funding Preferred Units will be entitled to be paid in cash, before any amount is paid or distributed to any holders of Funding Common Units, an amount per Funding Preferred Unit equal to the Redemption Price.

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Other Debt

VGLNG Senior Secured Notes

On May 26, 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. As of , 2024, $ aggregate principal amount of the VGLNG 2028 Notes remained outstanding and $ aggregate principal amount of the VGLNG 2031 Notes was outstanding.

On October 24, 2023, VGLNG issued $2.50 billion aggregate principal amount of 9.500% Senior Secured Notes due 2029, or the VGLNG 2029 Notes, and $1.50 billion aggregate principal amount of 9.875% Senior Secured Notes due 2032, or the VGLNG 2032 Notes. In addition, on November 8, 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. As of , 2024, $ aggregate principal amount of the VGLNG 2029 Notes remained outstanding and $ aggregate principal amount of the VGLNG 2032 Notes was outstanding.

On July 24, 2024, VGLNG issued $1.50 billion aggregate principal amount of 7.00% Senior Secured Notes due 2030, or the VGLNG 2030 Notes. The VGLNG 2030 Notes bear interest at a rate of 7.00% per annum and mature on January 15, 2030. The interest on such series of notes is payable semi-annually in arrears on each January 15 and July 15. As of , 2024, $ aggregate principal amount of the VGLNG 2030 Notes was outstanding.

The VGLNG 2028 Notes, the VGLNG 2029 Notes, the VGLNG 2030 Notes, the VGLNG 2031 Notes and the VGLNG 2032 Notes, or, collectively, the VGLNG Senior Secured Notes, were sold in a private offering that was exempt from the registration requirements of the Securities Act of 1933, as amended, or the Securities Act.

Guarantees and Security

The VGLNG Senior Secured Notes are senior secured obligations of VGLNG and, as of , 2024, are not guaranteed by any other entities. In the future, certain of VGLNG’s subsidiaries that incur or guarantee certain amounts of indebtedness will also be required to guarantee the VGLNG Senior Secured Notes, except during any period, or the Suspension Period, when the VGLNG Senior Secured Notes are rated investment grade by any one of S&P, Moody’s or Fitch.

The VGLNG Senior Secured Notes and the related guarantees are secured by first-priority liens in, subject to permitted liens and certain other exceptions, substantially all of the existing and future assets of VGLNG and the future guarantors, if any, including the direct wholly-owned subsidiaries of VGLNG that directly or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, the Delta Project or any related pipeline. The VGLNG Senior Secured Notes and the related guarantees of future guarantors, if any, will cease to be secured during any Suspension Period.

Optional Redemption

VGLNG may redeem some or all of (i) the VGLNG 2028 Notes at any time on or after June 1, 2025 and (ii) the VGLNG 2031 Notes at any time on or after June 1, 2026, in each case at the redemption prices set forth in the indenture governing such notes, plus accrued and unpaid interest, if any, to, but not including, the redemption

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date. Prior to June 1, 2025 and June 1, 2026, respectively, VGLNG may redeem some or all of such notes at 100% of the aggregate principal amount thereof redeemed plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to June 1, 2025 and June 1, 2026, respectively, VGLNG may redeem up to 40% of the then outstanding principal amount of such notes using the proceeds of certain equity offerings.

VGLNG may redeem some or all of (i) the VGLNG 2029 Notes at any time on or after November 1, 2028 and (ii) the VGLNG 2032 Notes at any time on or after February 1, 2027, in each case at the redemption prices set forth in the indenture governing such notes, plus accrued and unpaid interest, if any, to the redemption date. Prior to November 1, 2028 and February 1, 2027, respectively, VGLNG may redeem some or all of the notes at 100% of the aggregate principal amount thereof plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. In addition, with respect to the VGLNG 2032 Notes, at any time prior to February 1, 2027, VGLNG may redeem up to 40% of the then outstanding principal amount of the notes using the proceeds of certain equity offerings.

VGLNG may redeem some or all of the VGLNG 2030 Notes at any time on or after January 15, 2027 at the redemption prices set forth in the indenture governing such notes, plus accrued and unpaid interest, if any, to the redemption date. Prior to January 15, 2027, VGLNG may redeem some or all of the notes at 100% of the aggregate principal amount thereof plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to January 15, 2027, VGLNG may redeem up to 40% of the then outstanding principal amount of the notes using the proceeds of certain equity offerings.

Put Rights

Upon the occurrence of certain change of control triggering events with respect to the VGLNG Senior Secured Notes, VGLNG will be required to offer to repurchase the VGLNG Senior Secured Notes at a purchase price equal to 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the purchase date.

Negative Covenants

Each indenture governing the VGLNG Senior Secured Notes contains covenants that limit the ability of VGLNG and its restricted subsidiaries to, among other things:

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incur additional indebtedness, guarantee indebtedness or issue disqualified stock or, in the case of such subsidiaries, preferred stock;

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pay dividends on, repurchase or make distributions in respect of their capital stock or make other restricted payments;

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make certain investments or acquisitions;

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sell, transfer or otherwise convey certain assets;

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create liens;

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enter into agreements restricting certain subsidiaries’ ability to pay dividends or make other intercompany transfers;

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consolidate, merge, sell or otherwise dispose of all or substantially all of the assets of VGLNG and its restricted subsidiaries;

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enter into certain transactions with affiliates; and

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prepay certain kinds of indebtedness.

The covenants are subject to a number of exceptions and qualifications set forth in the indentures. In addition, certain of these covenants and the guarantee of each guarantor, if any, will be suspended during the Suspension Period.

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Events of Default

The indentures governing the VGLNG Senior Secured Notes also contain customary events of default, including (i) failure to pay principal or interest on the VGLNG Senior Secured Notes when due and payable; (ii) failure to comply with certain covenants or agreements in indenture if not cured or waived as provided in the indenture, as applicable and (iii) certain events of bankruptcy, insolvency, or reorganization. In the case of an event of default, the principal amount of the applicable VGLNG Senior Secured Notes plus accrued and unpaid interest would be accelerated.

If (1) a Change of Control (as defined in the indentures governing the VGLNG Senior Secured Notes) occurs and (2) the rating on the VGLNG Senior Secured Notes is lowered in respect of a Change of Control by two of S&P, Moody’s and Fitch, we must offer to repurchase the VGLNG Senior Secured Notes then outstanding at a price equal to 101% of the principal amount thereof plus any accrued and unpaid interest, if any, to, but not including, the repurchase date.

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSEQUENCES

FOR NON-U.S. HOLDERS OF COMMON STOCK

The following are the material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock acquired in this offering by a “Non-U.S. Holder” that does not own, and has not owned, actually or constructively, more than 5% of our common stock. You are a Non-U.S. Holder for U.S. federal income tax purposes if you are a beneficial owner of our common stock and are:

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a nonresident alien individual;

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a foreign corporation; or

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a foreign estate or trust.

You are not a Non-U.S. Holder if you are a nonresident alien individual present in the United States for 183 days or more in the taxable year of disposition, or if you are a former citizen or former resident of the United States for U.S. federal income tax purposes. If you are such a person, you should consult your tax advisor regarding the U.S. federal income tax consequences of the ownership and disposition of our common stock.

If you are an entity or arrangement treated as a partnership for U.S. federal income tax purposes, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and your activities. Partners and beneficial owners in partnerships or other pass-through entities that own our common stock should consult their own tax advisors as to the particular U.S. federal income and estate tax consequences applicable to them.

This discussion is based on the Internal Revenue Code of 1986, as amended to the date hereof (the “Code”), administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, changes to any of which subsequent to the date of this prospectus may affect the tax consequences described herein, possibly with retroactive effect. This discussion does not describe all of the tax consequences that may be relevant to you in light of your particular circumstances, including alternative minimum tax and Medicare contribution tax consequences and does not address any aspect of state, local or non-U.S. taxation, or any taxes other than income and estate taxes. In addition, this summary does not describe the U.S. federal income tax consequences applicable to you if you are subject to special treatment under U.S. federal income tax laws, including if you are a U.S. expatriate, a financial institution, an insurance company, a tax-exempt organization, a trader, broker or dealer in securities or currencies, a “controlled foreign corporation,” a “passive foreign investment company,” a person who acquired shares of our common stock as compensation or otherwise in connection with the performance of services, or a person who has acquired shares of our common stock as part of a straddle, hedge, conversion transaction or other integrated investment. You should consult your tax advisor with regard to the application of the U.S. federal tax laws to your particular situation, as well as any tax consequences arising under the laws of any state, local or non-U.S. taxing jurisdiction.

We have not sought and do not expect to seek any rulings from the U.S. Internal Revenue Service (the “IRS”) regarding the matters discussed below. There can be no assurance that the IRS will not take positions concerning the tax consequences of the ownership or disposition of shares of our common stock that differ from those discussed below.

Dividends

In the event that we do make distributions of cash or other property, those distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, they will constitute a return of capital, which will first reduce your basis in our common stock, but not below zero, and then will be treated as gain from the sale of our common stock, as described below under “—Gain on Disposition of Our Common Stock.”

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Dividends paid to you generally will be subject to withholding tax at a 30% rate or a reduced rate specified by an applicable income tax treaty. In order to obtain a reduced rate of withholding, you will be required to provide a properly executed applicable IRS Form W-8 certifying your entitlement to benefits under a treaty. If you do not timely furnish the required documentation, but you qualify for a lower treaty rate, you may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. You should consult your tax advisor regarding your entitlement to benefits under any applicable income tax treaty.

If dividends paid to you are effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base maintained by you in the United States), you will generally be taxed on the dividends in the same manner as a U.S. person. In this case, you will be exempt from the withholding tax discussed in the preceding paragraph, although you will be required to provide a properly executed IRS Form W-8ECI in order to claim an exemption from withholding. You should consult your tax advisor with respect to other U.S. tax consequences of the ownership and disposition of our common stock, including the possible imposition of a branch profits tax at a rate of 30% (or a lower treaty rate) if you are a corporation.

Gain on Disposition of Our Common Stock

Subject to the discussion below under “—Information Reporting and Backup Withholding” you generally will not be subject to U.S. federal income or withholding tax on gain realized on a sale or other taxable disposition of our common stock unless:

•

the gain is effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base maintained by you in the United States), or

•

we are or have been a “United States real property holding corporation” (a “USRPHC”) as described below, at any time within the five-year period preceding the disposition or your holding period, whichever period is shorter, and our common stock has ceased to be regularly traded on an established securities market prior to the beginning of the calendar year in which the sale or disposition occurs.

We will be a USRPHC at any time that the fair market value of our “United States real property interests,” as defined in the Code and applicable Treasury Regulations, equals or exceeds 50% of the aggregate fair market value of our worldwide real property interests and our 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) we expect a significant portion of our assets to consist of United States real property interests once we begin construction of our projects, there can be no assurance that we will not become a USRPHC at any point in time in the future. If we are or were to become a USRPHC at any point during the five-year period preceding your sale or other disposition of our common stock (or during your holding period, if shorter) and our common stock is not regularly traded on an established securities market during the calendar year in which your sale or other disposition of our common stock occurs, you would be subject to tax on the net gain from the sale or other disposition of our common stock (including a distribution treated as a sale of our common stock, as discussed above) under the regular graduated U.S. federal income tax rates applicable to U.S. persons and you could be subject to withholding at a 15% rate on the amount realized on such sale or disposition. You should consult your tax advisor regarding the particular U.S. federal income tax consequences of owning and disposing of our common stock.

If you recognize gain on a sale or other disposition of our common stock that is effectively connected with your conduct of a trade or business in the United States (and if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base maintained by you in the United States), you will generally be taxed on such gain in the same manner as a U.S. person. You should consult your tax advisor with

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respect to other U.S. tax consequences of the ownership and disposition of our common stock, including the possible imposition of a branch profits tax at a rate of 30% (or a lower treaty rate) if you are a corporation.

Information Reporting and Backup Withholding

Information returns are required to be filed with the IRS in connection with payments of distributions on our common stock, regardless of whether such distributions constitute dividends or whether any tax was actually withheld. Unless you comply with certification procedures to establish that you are not a U.S. person, information returns may also be filed with the IRS in connection with the proceeds from a sale or other disposition of our common stock. You may be subject to backup withholding on payments on our common stock or on the proceeds from a sale or other disposition of our common stock unless you comply with certification procedures to establish that you are not a U.S. person or otherwise establish an exemption. Your provision of a properly executed applicable IRS Form W-8 certifying your non-U.S. status will permit you to avoid backup withholding. Amounts withheld under the backup withholding rules are not additional taxes and may be refunded or credited against your U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

FATCA

Provisions of the Code commonly referred to as “FATCA” require withholding of 30% on payments of dividends on our common stock to “foreign financial institutions” (which is broadly defined for this purpose and in general includes investment vehicles) and certain other non-U.S. entities unless various U.S. information reporting and due diligence requirements (generally relating to ownership by U.S. persons of interests in or accounts with those entities) have been satisfied, or an exemption applies. Under proposed regulations promulgated by the Treasury Department on December 13, 2018, which state that taxpayers may rely on the proposed regulation until final regulations are issued, this withholding tax will not apply to the gross proceeds from the sale or other disposition of our common stock. An intergovernmental agreement between the United States and an applicable foreign country may modify these requirements. If FATCA withholding is imposed, a beneficial owner that is not a foreign financial institution generally may obtain a refund of any amounts withheld by filing a U.S. federal income tax return (which may entail significant administrative burden). You should consult your tax advisor regarding the effects of FATCA on your investment in our common stock.

Federal Estate Tax

Individual Non-U.S. Holders and entities the property of which is potentially includible in such an individual’s gross estate for U.S. federal estate tax purposes (for example, a trust funded by such an individual and with respect to which the individual has retained certain interests or powers), should note that, absent an applicable treaty exemption, our common stock will be treated as U.S.-situs property subject to U.S. federal estate tax.

THE SUMMARY OF MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS ABOVE IS INCLUDED FOR GENERAL INFORMATION PURPOSES ONLY. YOU ARE URGED TO CONSULT YOUR OWN TAX ADVISOR TO DETERMINE THE U.S. FEDERAL, STATE AND LOCAL AND NON-U.S. INCOME, ESTATE AND OTHER TAX CONSIDERATIONS OF OWNING AND DISPOSING OF OUR COMMON STOCK.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no market for our Class A common stock. Future sales of substantial amounts of our Class A common stock in the public market could adversely affect market prices prevailing from time to time. Furthermore, because only a limited number of shares will be available for sale shortly after this offering due to existing contractual and legal restrictions on resale as described below, there may be sales of substantial amounts of our Class A common stock in the public market after the restrictions lapse. This may adversely affect the prevailing market price and our ability to raise equity capital in the future.

Sales of Restricted Shares

Upon completion of this offering, a total of shares of Class A common stock (assuming no exercise of the underwriters’ option to purchase additional shares) and shares of Class B common stock will be outstanding. Of these shares, all of the Class A common stock sold in this offering by us, plus any shares sold by exercise of the underwriters’ option to purchase additional Class A common stock from us, will be freely tradable in the public market without restriction or further registration under the Securities Act, unless these shares are held by “affiliates,” as that term is defined in Rule 144 under the Securities Act. The remaining shares of Class A common stock and the shares of Class B common stock will be, and shares of Class A common stock subject to stock options will be on issuance, “restricted securities,” as that term is defined in Rule 144 under the Securities Act. These restricted securities are eligible for public sale only if they are registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which are summarized below. Restricted securities may also be sold outside of the United States to non-U.S. persons in accordance with Rule 904 of Regulation S.

Subject to the lock-up agreements described below and the provisions of Rule 144, Rule 701 or Regulation S under the Securities Act, as well as our insider trading policy, these restricted securities will be available for sale in the public market after the date of this prospectus as follows:


Number of Shares		Date
		On the date of this prospectus.

		After days from the date of this prospectus (subject, in some cases, to volume limitations).

Rule 144

In general, a person who has beneficially owned restricted shares of our common stock for at least six months would be entitled to sell such securities, provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the 90 days preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Persons who have beneficially owned restricted shares of our common stock for at least six months but who are our affiliates at the time of, or any time during the 90 days preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three month period only a number of securities that does not exceed the greater of either of the following:

•

1% of the number of shares of our Class A common stock then outstanding, which will equal approximately shares immediately after this offering, assuming no exercise of the underwriters’ option to purchase additional shares; or

•

the average weekly trading volume of our Class A common stock on during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale;

provided, in each case, that we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Such sales both by affiliates and by non-affiliates must also comply with the manner of sale, current public information and notice provisions of Rule 144 to the extent applicable.

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Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to resell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirements or other restrictions contained in Rule 701.

The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus. Securities issued in reliance on Rule 701 are restricted securities and, subject to the contractual restrictions described above, beginning 90 days after the date of this prospectus, may be sold by persons other than “affiliates,” as defined in Rule 144, subject only to the manner of sale provisions of Rule 144 and by “affiliates” under Rule 144 without compliance with its one-year minimum holding period requirement.

Registration Rights

Following completion of this offering, holders of shares of Class A common stock and shares of Class B common stock will be entitled to various rights with respect to the registration of these shares under the Securities Act. Registration of these shares under the Securities Act would result in these shares becoming freely tradable without restriction under the Securities Act immediately upon the effectiveness of the registration, except for shares purchased by affiliates. See “Certain Relationships and Related Party Transactions—Amended and Restated Shareholders’ Agreement”

Stock Options

As of , 2024 options to purchase a total of shares of Class A common stock were outstanding. shares subject to options are subject to lock-up agreements. An additional shares of Class A common stock were available for future grants under our equity incentive plans.

Upon completion of this offering, we intend to file a registration statement under the Securities Act covering all shares of Class A common stock subject to outstanding options or issuable pursuant to our equity incentive plans. Subject to Rule 144 volume limitations applicable to affiliates, shares registered under any registration statements will be available for sale in the open market, beginning 90 days after the date of the prospectus, except to the extent that the shares are subject to vesting restrictions with us or the contractual restrictions described below.

Lock-up Agreements

We have agreed, subject to certain exceptions, that we will not offer, pledge, sell, contract to sell or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any shares of our Class A common stock or securities convertible into or exchangeable or exercisable for any shares of our Class A common stock, or publicly disclose the intention to make any such offer, pledge, sale, disposition or filing, without the prior written consent of , for a period of days after the date of this prospectus.

have agreed, subject to certain exceptions, that they will not offer, pledge, sell, contract to sell or otherwise dispose of, directly or indirectly, any shares of our Class A common stock or securities convertible into or exchangeable or exercisable for any shares of our Class A common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our Class A common stock, whether any of these transactions are to

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be settled by delivery of our Class A common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, pledge, sale or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of for a period of days after the date of this prospectus. For more information, see “Underwriting.”

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UNDERWRITING

We and the underwriters named below have entered into an underwriting agreement with respect to the shares of our Class A common stock being offered in this offering. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares of our Class A common stock indicated in the following table. Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC are the representatives of the underwriters.


Underwriters		Number of Shares
Goldman Sachs & Co. LLC
J.P. Morgan Securities LLC

Total

The underwriters are committed to take and pay for all of the shares of our Class A common stock being offered in this offering, if any are taken, other than the shares of our Class A common stock covered by the option described below unless and until this option is exercised.

The underwriters have an option to buy up to an additional shares of our Class A common stock from us to cover sales by the underwriters of a greater number of shares of our Class A common stock than the total number set forth in the table above. They may exercise that option for 30 days after the date of this prospectus. If any shares of our Class A common stock are purchased pursuant to this option, the underwriters will severally purchase shares of our Class A common stock in approximately the same proportion as set forth in the table above.

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by us. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares of our Class A common stock from us.


	No-Exercise	Full-Exercise
Per Share	$	$
Total	$	$

Shares of our Class A common stock sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares of our Class A common stock sold by the underwriters to securities dealers may be sold at a discount of up to $ per share from the initial public offering price. After the initial offering of the shares of our Class A common stock, the representatives may change the offering price and the other selling terms. The offering of the shares of our Class A common stock by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We, and , have agreed, subject to certain exceptions, not to dispose of or hedge any shares of our Class A common stock or securities convertible into or exchangeable for shares of our Class A common stock during the period from the date of this prospectus continuing through the date that is days after the date of this prospectus, except with the prior written consent of .

Prior to this offering, there has been no public market for the shares of our Class A common stock. The initial public offering price has been negotiated among us and the representatives. Among the factors to be considered in determining the initial public offering price of the shares of our Class A common stock, in addition to prevailing market conditions, will be our historical performance, estimates of our business potential and our earnings prospects, an assessment of our management, and the consideration of the above factors in relation to market valuation of companies in related businesses.

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We intend to apply to list our Class A common stock on under the symbol “VG.”

In connection with this offering, the underwriters may purchase and sell shares of our Class A common stock in the open market. These transactions may include short sales, stabilizing transactions, and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in this offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A “covered short position” is a short position that is not greater than the amount of additional shares for which the underwriters’ option described above may be exercised. The underwriters may cover any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to cover the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option described above. “Naked” short sales are any short sales that create a short position greater than the amount of additional shares for which the option described above may be exercised. The underwriters must cover any such naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common stock made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of our Class A common stock, and together with the imposition of the penalty bid, may stabilize, maintain, or otherwise affect the market price of our Class A common stock. As a result, the price of our Class A common stock may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities and may end any of these activities at any time. These transactions may be effected on , in the over-the-counter market, or otherwise.

We estimate that the total expenses of this offering, excluding underwriting discounts and commissions, will be approximately $ . We have agreed to reimburse the underwriters for certain of their expenses relating to the clearance of this offering with the Financial Industry Regulatory Authority in an amount up to $ .

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that the underwriters may be required to make for these liabilities.

Relationships with the Underwriters and Their Affiliates

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include lending, sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage, and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to us and to persons and entities with relationships with us, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors, and employees may purchase, sell, or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps, and other financial instruments for

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their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to our assets, securities, and/or instruments (directly, as collateral securing other obligations, or otherwise) and/or persons and entities with relationships with us. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas, and/or publish or express independent research views in respect of such assets, securities, or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities, and instruments.

Selling Restrictions

Notice to Prospective Investors in the European Economic Area

In relation to each European Economic Area Member State, or each a Relevant Member State, no shares of our Class A common stock have been offered or will be offered pursuant to this offering to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares of our Class A common stock which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Regulation, except that the shares of our Class A common stock may be offered to the public in that Relevant Member State at any time:

•

to any legal entity which is a qualified investor as defined under Article 2 of the Prospectus Regulation;

•

to fewer than 150 natural or legal persons (other than qualified investors as defined under Article 2 of the Prospectus Regulation) subject to obtaining the prior consent of the joint book-running managers for any such offer; or

•

in any other circumstances falling within Article 1(4) of the Prospectus Regulation;

provided that no such offer of the shares of our Class A common stock shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Regulation or supplement a prospectus pursuant to Article 23 of the Prospectus Regulation.

For the purposes of this provision, the expression an “offer to the public” in relation to the shares of our Class A common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares of our Class A common stock to be offered so as to enable an investor to decide to purchase any shares of our Class A common stock, and the expression “Prospectus Regulation” means Regulation (EU) 2017/1129.

Each person in a Relevant Member State who receives any communication in respect of, or who acquires any shares of our Class A common stock in, this offering will be deemed to have represented, warranted, and agreed to and with each of the underwriters and their affiliates and us that:

•

it is a qualified investor within the meaning of the Prospectus Regulation; and

•

in the case of any shares of our Class A common stock acquired by it as a financial intermediary, as that term is used in Article 5 of the Prospectus Regulation, (i) the shares of our Class A common stock acquired by it in this offering have not been acquired on a non-discretionary basis on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than qualified investors, as that term is defined in the Prospectus Regulation, or have been acquired in other circumstances falling within the points (a) to (d) of Article 1(4) of the Prospectus Regulation and the prior consent of the joint book-running managers has been given to the offer or resale; or (ii) where the shares of our Class A common stock have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of those shares of our Class A common stock to it is not treated under the Prospectus Regulation as having been made to such persons.

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We, the underwriters and their affiliates, and others will rely upon the truth and accuracy of the foregoing representation, acknowledgement, and agreement. Notwithstanding the above, a person who is not a qualified investor and who has notified the joint book-running managers of such fact in writing may, with the prior consent of the joint book-running managers, be permitted to acquire shares of our Class A common stock in this offering.

This European Economic Area selling restriction is in addition to any other selling restrictions set out below.

Notice to Prospective Investors in the United Kingdom

In relation to the United Kingdom, no shares of our Class A common stock have been offered or will be offered pursuant to this offering to the public in the United Kingdom prior to the publication of a prospectus in relation to the shares of our Class A common stock which has been approved by the Financial Conduct Authority in accordance with the transition provisions in Regulation 74 of the Prospectus (Amendment etc.) (EU Exit) Regulations 2019, except that it may make an offer to the public in the United Kingdom of any shares of our Class A common stock at any time under the following exemptions under the UK Prospectus Regulation:

•

to any legal entity which is a qualified investor as defined under Article 2 of the UK Prospectus Regulation;

•

to fewer than 150 natural or legal persons (other than qualified investors as defined under the UK Prospectus Regulation), subject to obtaining the prior consent of the representatives for any such offer; or

•

in any other circumstances falling within section 86 of the Financial Services and Markets Act 2000, as amended, or the FSMA;

provided that no such offer of the shares of our Class A common stock shall require the issuer or any underwriter to publish a prospectus pursuant to section 85 of the FSMA or supplement a prospectus pursuant to Article 23 of the UK Prospectus Regulation.

In the United Kingdom, this offering is only addressed to, and is directed only at, “qualified investors” within the meaning of Article 2(e) of the UK Prospectus Regulation, who are also (i) persons having professional experience in matters relating to investments who fall within the definition of “investment professionals” in Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or the Order; (ii) high net worth entities or other persons falling within Article 49(2)(a) to (d) of the Order; or (iii) persons to whom it may otherwise lawfully be communicated, or all such persons being referred to as relevant persons. This document must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this document relates is available only to relevant persons and will be engaged in only with relevant persons.

For the purposes of this provision, the expression an “offer to the public” in relation to the shares of our Class A common stock in the United Kingdom means the communication in any form and by any means of sufficient information on the terms of the offering and any shares of our Class A common stock to be offered so as to enable an investor to decide to purchase or subscribe for any shares of our Class A common stock, and the expression “UK Prospectus Regulation” means the Regulation (EU) 2017/1129 as it forms part of domestic law by virtue of the European Union (Withdrawal) Act 2018.

Each person in the UK who acquires any shares of our Class A common stock in the offer or to whom any offer is made will be deemed to have represented, acknowledged, and agreed to and with us, the underwriters, and their affiliates that it meets the criteria outlined in this section.

Notice to Prospective Investors in Canada

The shares of our Class A common stock may be sold in Canada only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus

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Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions, and Ongoing Registrant Obligations. Any resale of the shares of our Class A common stock must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Notice to Prospective Investors in Hong Kong

The shares of our Class A common stock may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies (Winding Up and Miscellaneous Provisions) Ordinance (Cap. 32 of the Laws of Hong Kong), or the Companies (Winding Up and Miscellaneous Provisions) Ordinance, or which do not constitute an invitation to the public within the meaning of the Securities and Futures Ordinance (Cap. 571 of the Laws of Hong Kong), or the Securities and Futures Ordinance, or (ii) to “professional investors” as defined in the Securities and Futures Ordinance and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies (Winding Up and Miscellaneous Provisions) Ordinance, and no advertisement, invitation or document relating to the shares of our Class A common stock may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” in Hong Kong as defined in the Securities and Futures Ordinance and any rules made thereunder.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares of our Class A common stock may not be circulated or distributed, nor may the shares of our Class A common stock be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor (as defined under Section 4A of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA) under Section 274 of the SFA, (ii) to a relevant person (as defined in Section 275(2) of the SFA) pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to conditions set forth in the SFA.

Where the shares of our Class A common stock are subscribed or purchased under Section 275 of the SFA by a relevant person which is a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor, the securities (as defined in Section 239(1) of the SFA) of that corporation shall not be transferable for six months after that corporation has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant

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person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer in that corporation’s securities pursuant to Section 275(1A) of the SFA, (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore, or Regulation 32.

Where the shares of our Class A common stock are subscribed or purchased under Section 275 of the SFA by a relevant person which is a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole purpose is to hold investments and each beneficiary of the trust is an accredited investor, the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for six months after that trust has acquired the shares of our Class A common stock under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer that is made on terms that such rights or interest are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction (whether such amount is to be paid for in cash or by exchange of securities or other assets), (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32.

Singapore SFA Product Classification — In connection with Section 309B of the SFA and the Securities and Futures (Capital Markets Products) Regulations 2018, or the CMP Regulations 2018, we have determined, and hereby notify all relevant persons (as defined in the CMP Regulations 2018), that the shares of our Class A common stock are “prescribed capital markets products” (as defined in the CMP Regulations 2018) and Excluded Investment Products (as defined in MAS Notice SFA 04-N12: Notice on the Sale of Investment Products and MAS Notice FAA-N16: Notice on Recommendations on Investment Products).

Notice to Prospective Investors in Japan

The shares of our Class A common stock have not been and will not be registered under the Financial Instruments and Exchange Act of Japan (Act No. 25 of 1948, as amended), or the FIEA. The shares of our Class A common stock may not be offered or sold, directly or indirectly, in Japan or to or for the benefit of any resident of Japan (including any person resident in Japan or any corporation or other entity organized under the laws of Japan) or to others for reoffering or resale, directly or indirectly, in Japan or to or for the benefit of any resident of Japan, except pursuant to an exemption from the registration requirements of the FIEA and otherwise in compliance with any relevant laws and regulations of Japan.

Notice to Prospective Investors in Switzerland

The shares of our Class A common stock may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange, or SIX, or on any other stock exchange or regulated trading facility in Switzerland. This document does not constitute a prospectus within the meaning of, and has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or this offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to this offering, us or the shares of our Class A common stock have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares of our Class A common stock will not be supervised by, the Swiss Financial Market Supervisory Authority, and the offer of shares of our Class A common stock has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes, or CISA. The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares of our Class A common stock.

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Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement, or other disclosure document has been lodged with the Australian Securities and Investments Commission in relation to this offering. This prospectus does not constitute a prospectus, product disclosure statement, or other disclosure document under the Corporations Act 2001, or the Corporations Act, and does not purport to include the information required for a prospectus, product disclosure statement, or other disclosure document under the Corporations Act.

Any offer in Australia of the shares of our Class A common stock may only be made to persons, or the Exempt Investors, who are “sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act), or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the shares of our Class A common stock without disclosure to investors under Chapter 6D of the Corporations Act.

The shares of our Class A common stock applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under this offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring shares of our Class A common stock must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation, or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives, and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in the Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority, or DFSA. This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares of our Class A common stock to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of our Class A common stock should conduct their own due diligence on such shares. If you do not understand the contents of this prospectus, you should consult an authorized financial advisor.

Notice to Prospective Investors in the United Arab Emirates

The shares of our Class A common stock have not been, and are not being, publicly offered, sold, promoted or advertised in the United Arab Emirates (including the DIFC) other than in compliance with the laws of the United Arab Emirates (and the DIFC) governing the issue, offering and sale of securities. Further, this prospectus does not constitute a public offer of securities in the United Arab Emirates (including the DIFC) and is not intended to be a public offer. This prospectus has not been approved by or filed with the Central Bank of the United Arab Emirates, the Securities and Commodities Authority or the DFSA.

Notice to Prospective Investors in Brazil

The offer and sale of the securities have not been and will not be registered with the Brazilian securities commission (COMISSÃO DE VALORES MOBILIÁRIOS, or “CVM”) and, therefore, will not be carried out by

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any means that would constitute a public offering in Brazil under CVM resolution no 160, dated 13 July 2022, as amended (“CVM resolution 160”) or unauthorized distribution under Brazilian laws and regulations. The securities may only be offered to Brazilian professional investors (as defined by applicable CVM regulation), who may only acquire the securities through a non-Brazilian account, with settlement outside Brazil in non-Brazilian currency. the trading of these securities on regulated securities markets in Brazil is prohibited.

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LEGAL MATTERS

The validity of the issuance of the shares of Class A common stock offered hereby will be passed upon for Venture Global, Inc. by Davis Polk & Wardwell LLP, New York, New York. Various legal matters will be passed upon for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York.

EXPERTS

The consolidated financial statements of Venture Global, Inc. as of December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, appearing in this prospectus and registration statement, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the Class A common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the company and its Class A common stock, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. In addition, the SEC maintains an Internet site at www.sec.gov, from which interested persons can electronically access the registration statement, including the exhibits and any schedules thereto.

As a result of the offering, we will be required to file periodic reports and other information with the SEC. We also maintain a website at www.venturegloballng.com. Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this prospectus or the registration statement of which it forms a part and is included in this prospectus as an inactive textual reference only.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Annual Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2023 and 2022		F-4
Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021		F-5
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021		F-6
Consolidated Statements of Changes in Equity (Deficit) for the years ended December 31, 2023, 2022 and 2021		F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021		F-8
Notes to the Consolidated Financial Statements		F-9
Schedule I Condensed Financial Information of Parent
Report of Independent Registered Public Accounting Firm		F-43
Condensed Balance Sheets as of December 31, 2023 and 2022		F-44
Condensed Statements of Operations for the years ended December 31, 2023, 2022 and 2021		F-45
Condensed Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021		F-46
Notes to the Condensed Financial Information of Parent		F-47

F-1

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Venture Global, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Venture Global, Inc. (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), changes in equity (deficit) and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to those charged with governance and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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Accounting for Costs of Construction and Development



Description of the Matter		As described in Note 2 to the consolidated financial statements, the Company’s liquefied natural gas (“LNG”) projects are constructed pursuant to the terms of construction and equipment supplier arrangements. The treatment of the costs incurred under these arrangements is dependent on the project’s stage of development. As described in Note 2, generally, the costs incurred to develop the Company’s LNG projects are recognized as development expenses until management concludes that construction and completion of the project is probable; afterwards such costs are capitalized. As of December 31, 2023, the Company had capitalized costs of approximately $19.4 billion into Property, plant, and equipment, net and had recognized expenses for development of LNG projects of approximately $0.5 billion during the year then ended. The construction and equipment supplier arrangements also contain various terms including retainage, performance bonuses, and liquidated damages, that impact the amount and timing of the recognition of the related costs.

		Auditing the Company’s costs of construction and development involved an increased extent of audit effort to evaluate treatment as being capitalized or expensed and whether they were recorded consistent with the terms of the construction and equipment supplier agreements in accordance with accounting principles generally accepted in the United States of America (US GAAP).

How We Addressed the Matter in Our Audit		Our audit procedures included, among others, inspection of a sample of the construction and equipment supplier arrangements, amendments, and any change orders to understand the key terms and conditions. We confirmed the terms and conditions directly with a sample of the Company’s major construction and equipment suppliers. For a sample of costs recognized during the year, we inspected invoices, construction reports and other supporting documents to test that they were recognized at the correct amount, in the correct period, and were recognized as capital or expense in accordance with the Company’s probability assessment of the related LNG project. Further, we obtained and tested the Company’s assessment of the probability of each LNG project being constructed and completed; including testing whether appropriate regulatory approvals, permits, LNG off-take contracts and construction and supplier contracts had been obtained.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2020.

Tysons, VA

February 22, 2024

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

CONSOLIDATED BALANCE SHEETS

($ in millions, except par values and share amounts)


	December 31,
	2023			2022
ASSETS
Current assets
Cash and cash equivalents	$	4,823		$	618
Restricted cash		520			391
Accounts receivable		265			190
Inventory		44			26
Derivative assets		164			146
Prepaid expenses and other current assets		143			41

Total current assets		5,959			1,412

Property, plant and equipment, net		19,439			10,606
Right-of-use assets		381			327
Noncurrent restricted cash		529			1,403
Deferred financing costs		464			304
Noncurrent derivative assets		899			973
Equity method investments		539			—
Other noncurrent assets		253			72

TOTAL ASSETS	$	28,463		$	15,097

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	436		$	252
Accrued and other liabilities		1,701			1,344
Current portion of long-term debt		178			150

Total current liabilities		2,315			1,746

Long-term debt, net including $4,944 and $0, respectively, of debt related to variable interest entities		20,607			10,458
Noncurrent operating lease liabilities		383			337
Deferred tax liabilities, net		1,149			474
Other noncurrent liabilities		539			318

Total liabilities		24,993			13,333

Commitments and contingencies (Note 15)
Redeemable stock of subsidiary		1,385			1,255
Equity
Venture Global, Inc. stockholders’ and members’ equity (deficit)
Class A common stock, par value $0.01 per share (519,772 shares issued and outstanding at December 31, 2023 and 0 shares issued and outstanding at December 31, 2022)		—			—
Members’ deficit		—			(690	)
Additional paid in capital		542			—
Retained earnings		1,228			688
Accumulated other comprehensive loss		(260	)		(184	)

Total Venture Global, Inc. stockholders’ and members’ equity (deficit)		1,510			(186	)
Non-controlling interests		575			695

Total equity		2,085			509

TOTAL LIABILITIES AND EQUITY	$	28,463		$	15,097

The accompanying notes are an integral part of these consolidated financial statements.

F-4

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except share and per share amounts)


	Years ended December 31,
	2023			2022			2021
REVENUE	$	7,897		$	6,448		$	—

OPERATING EXPENSE
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,684			2,093			—
Operating and maintenance expense		391			140			58
General and administrative expense		224			191			89
Development expense		490			311			188
Depreciation and amortization		277			158			6
Insurance recoveries, net		(19	)		—			(4	)

Total operating expense		3,047			2,893			337

INCOME (LOSS) FROM OPERATIONS		4,850			3,555			(337	)
OTHER INCOME (EXPENSE)
Interest income		172			18			—
Interest expense, net		(641	)		(592	)		(52	)
Gain on derivatives, net		174			1,212			38
Gain (loss) on embedded derivative		—			(14	)		12
Loss on financing transactions		(123	)		(635	)		(97	)

Total other expense		(418	)		(11	)		(99	)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE		4,432			3,544			(436	)
Income tax expense		816			447			—

NET INCOME (LOSS)	$	3,616		$	3,097		$	(436	)

Less: Net income attributable to redeemable stock of subsidiary		130			118			107
Less: Net income (loss) attributable to non-controlling interests		805			1,121			(187	)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AND MEMBERS	$	2,681		$	1,858		$	(356	)

BASIC EARNINGS (LOSS) PER SHARE
Net income attributable to common stockholders per share—basic	$	5,855		$	4,266		$	(817	)
Weighted average number of shares of common stock outstanding—basic^(a)		457,896			435,500			435,500
DILUTED EARNINGS (LOSS) PER SHARE
Net income attributable to common stockholders per share—diluted	$	5,656		$	4,266		$	(817	)
Weighted average number of shares of common stock outstanding—diluted ^(a)		474,033			435,500			435,500

(a)	See Note 20 – Earnings (Loss) per Share for further discussion regarding the weighted average number of shares of common stock outstanding.

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

($ in millions)


	Years ended December 31,
	2023			2022		2021
NET INCOME (LOSS)	$	3,616		$	3,097	$	(436	)
Other comprehensive income (loss)
Cash flow hedges, net
Change in fair value, net of income tax (expense) benefit of $2, $(25), and $0, respectively		(8	)		88		70
Reclassification to earnings, net of income tax expense of $1, $3, and $0, respectively		4			7		—

Total change in cash flow hedges, net		(4	)		95		70

COMPREHENSIVE INCOME (LOSS)	$	3,612		$	3,192	$	(366	)

Less: Comprehensive income attributable to redeemable stock of subsidiary		130			118		107
Less: Comprehensive income (loss) attributable to non-controlling interests		803			1,156		(159	)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS AND MEMBERS	$	2,679		$	1,918	$	(314	)

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (DEFICIT)

($ in millions, except share amounts)


	Stockholders’ and members’ equity (deficit)
	Common stock				Members’ capital			Additional paid in capital			Retained earnings (deficit)			Accumulated other comprehensive loss			Total stockholders’ and members’ equity (deficit)			Non-controlling interests
	Class A
	Shares		Par value
BALANCE AT DECEMBER 31, 2020		—	$	—	$	446		$	—		$	(814	)	$	(246	)	$	(614	)	$	89
Net loss		—		—		—			—			(356	)		—			(356	)		(187	)
Stock-based compensation		—		—		—			—			—			—			—			20
Distributions		—		—		(7	)		—			—			—			(7	)		—
Other comprehensive income		—		—		—			—			—			42			42			28
Purchase of non-controlling interests		—		—		(222	)		—			—			(18	)		(240	)		56

BALANCE AT DECEMBER 31, 2021		—		—		217			—			(1,170	)		(222	)		(1,175	)		6

Net income		—		—		—			—			1,858			—			1,858			1,121
Stock-based compensation		—		—		—			—			—			—			—			26
Distributions		—		—		(6	)		—			—			—			(6	)		—
Other comprehensive income		—		—		—			—			—			60			60			35
Purchase of non-controlling interests		—		—		(901	)		—			—			(22	)		(923	)		(493	)

BALANCE AT DECEMBER 31, 2022		—		—		(690	)		—			688			(184	)		(186	)		695

Net income		—		—		—			—			2,681			—			2,681			805
Stock-based compensation		—		—		—			(141	)		—			—			(141	)		17
Distributions		—		—		—			—			(149	)		—			(149	)		(29	)
Other comprehensive loss		—		—		—			—			—			(2	)		(2	)		(2	)
Merger of Legacy VG Partners with Venture Global (the 2023 Merger)		435,500		—		1,781			171			(1,992	)		—			(40	)		—
Purchase of non-controlling interests		84,272		—		(1,091	)		512			—			(74	)		(653	)		(911	)

BALANCE AT DECEMBER 31, 2023		519,772	$	—	$	—		$	542		$	1,228		$	(260	)	$	1,510		$	575

The accompanying notes are an integral part of these consolidated financial statements.

F-7

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in millions)


	Years ended December 31,
	2023			2022			2021
OPERATING ACTIVITIES
Net income (loss)	$	3,616		$	3,097		$	(436	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Gain on derivatives, net		(174	)		(1,198	)		(50	)
Net cash from (used for) settlement of derivatives		203			(5	)		(231	)
Loss on financing transactions		122			630			95
Deferred taxes		674			446			—
Non-cash interest expense		85			218			15
Depreciation and amortization		277			158			6
Stock-based compensation		28			26			20
Reduction of right-of-use assets		23			15			7
Changes in operating assets and liabilities:
Accounts receivable		(75	)		(190	)		—
Inventory		(18	)		(26	)		—
Prepaid expenses and other current assets		(96	)		10			(22	)
Accounts payable and accrued liabilities		(55	)		541			66
Operating lease liabilities		(29	)		(9	)		2
Other, net		(31	)		(11	)		25

Net cash from (used by) operating activities		4,550			3,702			(503	)

INVESTING ACTIVITIES
Purchases of property, plant and equipment		(8,091	)		(4,618	)		(2,009	)
Deposits for construction services and equipment		(64	)		(96	)		(70	)
Proceeds from test LNG sales		—			1,797			—
Purchase of equity method investments		(539	)		—			—
Maturities of investments—certificates of deposit		72			50			12
Purchases of investments—certificates of deposit		(88	)		(30	)		(1	)
Other investing activities		(15	)		(3	)		(10	)

Net cash used by investing activities		(8,725	)		(2,900	)		(2,078	)

FINANCING ACTIVITIES
Proceeds from issuance of debt		12,278			5,974			5,396
Proceeds from project credit facilities		3,875			1,695			2,375
Repayment of debt		(5,918	)		(5,043	)		(3,272	)
Purchase of non-controlling interests		(1,564	)		(1,417	)		(185	)
Payments of financing and issuance costs		(591	)		(886	)		(134	)
Distributions		(164	)		(6	)		(7	)
Financed purchases of property, plant and equipment		(108	)		(67	)		(267	)
Other financing activities		(173	)		(15	)		(283	)

Net cash from financing activities		7,635			235			3,623

Net increase in cash, cash equivalents and restricted cash		3,460			1,037			1,042
Cash, cash equivalents and restricted cash at beginning of period		2,412			1,375			333

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	5,872		$	2,412		$	1,375

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – The Company

Venture Global, Inc. (“Venture Global”) is a Delaware corporation formed by the managing members of Venture Global Partners II, LLC (“VG Partners”) on September 19, 2023, under the name of Venture Global Holdings, Inc. In January 2024, the Company changed its name from Venture Global Holdings, Inc. to Venture Global, Inc. As used in these consolidated financial statements, unless the context otherwise requires, references to the “Company,” “we,” “us,” and “our” refer to Venture Global (or Legacy VG Partners, as applicable, and as defined and explained below) and its consolidated subsidiaries.

In September 2023, Venture Global was party to certain reorganization transactions (the “Reorganization Transactions”) whereby Venture Global Partners, LLC (“Legacy VG Partners”), a then wholly-owned subsidiary of VG Partners and controlling shareholder of Venture Global LNG, Inc. (“VGLNG”), merged with and into Venture Global (the “2023 Merger”), with VG Partners receiving 435,500 shares of Venture Global’s Class A common stock in exchange for 100% of its equity interests in Legacy VG Partners. In connection with the Reorganization Transactions, the non-controlling VGLNG shareholders, holding 84,272 shares of VGLNG’s issued and outstanding Series C common stock, received 84,272 shares of Class A common stock of Venture Global, in a one-for-one exchange for their shares of VGLNG (the “NCI Acquisition”). All shares of Series A, Series B and Series C common stock of VGLNG were retired upon completion of the Reorganization Transactions in September 2023. No cash was exchanged as part of the Reorganization Transactions and Venture Global incurred $40 million of third- party transaction costs in connection with its formation and the issuance of its shares of Class A common stock.

The 2023 Merger was accounted for as a transaction between entities under common control which represented a change in reporting entity. The NCI Acquisition was accounted for as a change in Venture Global’s ownership interest in a subsidiary within equity on a prospective basis. Prior to the 2023 Merger, Venture Global, as a standalone entity, had no operations, and no assets or liabilities. The financial results and other information included in these consolidated financial statements for periods prior to the Reorganization Transactions were applied on a retrospective basis and are reflective of Legacy VG Partners, except for earnings per share. Historical earnings per share was calculated based on the one-for-one exchange ratio of the 435,500 shares of Venture Global’s Class A common stock issued to VG Partners in exchange for 100% of the Legacy VG Partners equity interests in connection with the 2023 Merger. The shares issued as part of the NCI Acquisition are included in earnings per share prospectively from the date of the Reorganization Transactions. See Note 20 – Earnings (Loss) per Share for further discussion.

The Company is headquartered in Arlington, Virginia, and has offices in Houston, Texas; London, England; Tokyo, Japan; and Singapore.

The Company sells liquefied natural gas (“LNG”) and is engaged in the development, construction, and operation of natural gas liquefaction and export facilities in North America (“LNG projects”). Each LNG project includes a liquefaction facility and export terminal and one or more associated pipelines that interconnect with several interstate and intrastate pipelines for delivery of natural gas into the associated liquefaction facility and export terminal. Below is a summary of our current LNG projects.


Project name	Terminal entity	Pipeline(s) entity
Calcasieu Pass Project	Venture Global Calcasieu Pass, LLC (“Calcasieu Pass”)	TransCameron Pipeline, LLC (“TransCameron”)

Plaquemines Project	Venture Global Plaquemines LNG, LLC (“Plaquemines”)	Venture Global Gator Express, LLC (“Gator Express”)

CP2 LNG Project	Venture Global CP2 LNG, LLC (“CP2”)	Venture Global CP Express, LLC (“CP Express”)

Delta LNG Project	Venture Global Delta LNG, LLC (“Delta”)	Venture Global Delta Express, LLC (“Delta Express”)

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Commencement of the construction of each of our LNG projects is subject to the receipt of the appropriate regulatory approvals and permits, entering into LNG sales contracts with respect to an adequate amount of anticipated nameplate capacity, securing equipment and construction contracts and securing adequate financing arrangements.

The Calcasieu Pass Project has contracted to sell 10.0 million metric tonnes per annum (“MTPA”) of LNG under six 20-year, one 5-year, and one 3-year sales and purchase agreements (“SPAs”) on a post-commercial operation date (“COD”) term basis. The Calcasieu Pass Project is located in Cameron Parish, Louisiana on leased land with access to deep-water frontage on the Calcasieu Ship Channel near the Gulf of Mexico. In the first quarter of 2022, the Company began producing and selling LNG from the Calcasieu Pass Project while undergoing commissioning. The Calcasieu Pass Project is still in its commissioning phase and various corrective, remedial, warranty and other work is being performed before the facility can be declared complete and commercially operable for the purposes of its post-COD term SPAs.

The Plaquemines Project is being built in two phases. The Plaquemines Project has contracted to sell 13.3 MTPA and 6.7 MTPA of LNG from the first and second phase of the Plaquemines Project, respectively, under 14 predominantly 20-year SPAs on a post-COD term basis. The Plaquemines Project is located in Plaquemines Parish, Louisiana on leased land with access to deep-water frontage on the Mississippi River near the Gulf of Mexico. The Plaquemines Project is under construction after securing the full project-level financing required to complete the first and second phases of the project.

The CP2 LNG Project is expected to be built in two phases. The CP2 LNG Project has contracted to sell 9.25 MTPA of LNG from the CP2 LNG Project under eight 20-year SPAs on a post-COD term basis. The CP2 LNG Project is located in Cameron Parish, Louisiana near the Calcasieu Pass Project on the Calcasieu Ship Channel near the Gulf of Mexico. The CP2 LNG Project is in the development and permitting phase with major engineering and procurement work underway, and has yet to secure the full project-level financing required to complete the first phase of the project. While the Federal Energy Regulatory Commission (“FERC”) has issued the final Environmental Impact Statement (“EIS”) for the CP2 LNG Project, the final FERC order on the CP2 LNG Project application and the approval from the Department of Energy (“DOE”) to export LNG produced by the CP2 LNG Project to non-free trade agreement (“non-FTA”) nations are still pending.

The Delta LNG Project is expected to be built in two phases. The Delta LNG Project is located in Plaquemines Parish, Louisiana with access to deep-water frontage on the Mississippi River near the Gulf of Mexico. The Delta LNG Project is in the early permitting and development phase and has yet to secure the full project-level financing and regulatory permits and approvals required to complete the first phase of the project. The Delta LNG Project received acceptance from FERC of its pre-filing submission, starting the environmental review process.

The Company is also engaged in the acquisition, and eventual operation and management, of LNG tankers to support its LNG projects. The Company has five LNG tankers under construction which are expected to be delivered on a rolling basis between 2025 through 2026. The Company has contracts to acquire four additional LNG tankers through the purchase of equity interests in certain third party entities, which are expected to be delivered between 2024 through 2025. See Note 8 – Equity Method Investments for further discussion.

Note 2 – Summary of Significant Accounting Policies

Basis of presentation and consolidation

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The consolidated financial statements include the accounts of Venture Global and its controlled subsidiaries. All intercompany transactions and balances have

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

been eliminated in consolidation. The financial results and other information included in these consolidated financial statements for periods prior to the Reorganization Transactions are reflective of Legacy VG Partners, except for earnings per share.

Variable interest entities

Entities in which the Company has variable interests (“VIEs”) have been consolidated where the Company is the primary beneficiary. Plaquemines and Gator Express were determined to be wholly-owned VIEs due to the financing structure of the second phase of the Plaquemines Project. The Company is the primary beneficiary of Plaquemines and Gator Express since it has the power to make significant decisions. The assets held by Plaquemines and Gator Express are restricted to use on those entities. See Note 3 – Restricted Cash and Note 6 – Property, Plant and Equipment for further discussion.

Going concern

The consolidated financial statements have been prepared under the assumption the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Management expects to have sufficient financial resources to operate beyond the next twelve months following the date these consolidated financial statements are issued.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Use of estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and in the accompanying notes. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist primarily of derivative instruments and accounts receivable related to our LNG sales contracts. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Exposure to credit risk is limited to the amounts, if any, by which the counterparty’s obligations under the derivative contracts exceed the obligations of the Company to the counterparty. The Company mitigates this exposure by minimizing counterparty concentrations, entering into master netting arrangements and generally entering into derivative contracts with large multinational financial institutions. The Company does not believe there is a material risk of counterparty non-performance.

The Company is dependent on our customers’ creditworthiness and their willingness to perform under their respective agreements. See Note 23 – Segment Information for additional details about our customer concentration.

Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The carrying values of the Company’s Cash and cash equivalents, Restricted cash,

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Accounts receivable, Accounts payable and Accrued and other liabilities approximate fair value due to their short-term maturities. The Company applies the fair value measurement guidance to financial assets and liabilities included in the Cash and cash equivalents, Derivative assets, Noncurrent derivative assets, Accrued and other liabilities and Other noncurrent liabilities line items on the Consolidated Balance Sheets. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. In determining fair value, the Company prioritizes the use of observable market data when available. Assets and liabilities are categorized within the fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•

Level 1: Quoted prices in active markets for identical assets or liabilities

•

Level 2: Inputs other than quoted prices in active markets that are directly or indirectly observable for the asset or liability

•

Level 3: Inputs that are not observable in the market

Transfers between Level 2 and Level 3 result from changes in the significance of unobservable inputs used to determine fair value and are recognized as of the beginning of the reporting period in which they occur. For further discussion, see Note 13 – Fair Value Measurements.

Cash and cash equivalents

The Company considers money market funds, commercial paper and all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.

Restricted cash

The Company holds certain financial instruments that are restricted as to withdrawal and use under the terms of certain contractual arrangements. These amounts are presented separately from Cash and cash equivalents on the Consolidated Balance Sheets. For further discussion, see Note 3 – Restricted Cash.

Revenue recognition

The majority of the Company’s nameplate liquefaction capacity produced after an LNG project reaches commercial operations will be sold under long-term 20-year SPAs (“post-COD term SPAs”). In this context, “commercial operations” represents the production period commencing after the occurrence of the commercial operations date (“COD”) of the relevant project or phase thereof as specifically defined in the relevant SPAs. Under each post-COD term SPA, COD does not occur unless and until: (i) all of the facilities comprising the relevant project or phase thereof, have been completed and commissioned, including any ramp up period, (ii) the project or phase thereof is capable of delivering LNG in sufficient quantities and necessary quality to perform all of its obligations under the post-COD term SPA, and (iii) the applicable project company has notified the customer.

LNG produced prior to the relevant project or phase thereof reaching COD is sold under short-term sales agreements (“Early Cargo Sales Agreements”), at prevailing market prices when executed. COD has not yet occurred for any of our LNG projects or phases thereof, and accordingly, LNG revenue recognized during the years ended December 31, 2023 and 2022, was earned under Early Cargo Sales Agreements.

The Company recognizes 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

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 individual molecule of LNG is viewed as a separate performance obligation. 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. 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 (“test LNG sales”) 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.

Accounts receivable

Accounts receivable are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on counterparty credit worthiness, past events, current conditions and reasonable and supportable forecasts. There were no allowances for credit losses as of December 31, 2023 or 2022.

Inventory

Inventory consists of LNG inventory, spare parts and materials, and is recognized at the lower of weighted average cost and net realizable value. LNG inventory includes all costs incurred directly for the production of LNG. LNG inventory is recognized as Cost of sales, or as part of the cost basis of construction in progress if associated with test LNG sales, when transferred to the customer. Spare parts and materials are charged to Operating and maintenance expense as they are consumed.

Property, plant and equipment

Property, plant and equipment are recognized at cost, less accumulated depreciation and amortization. Certain assets undergo a commissioning process during which LNG is produced and sold as test LNG. Prior to being placed in service in accordance with the accounting guidance, net margin from test LNG sales, including sale proceeds and costs of production, are treated as a reduction of construction in progress. Depreciation is calculated using the straight-line depreciation method over the estimated useful life of the asset. The LNG terminal assets are depreciated on a straight-line basis over the shorter of their estimated useful life or the lease term of the land to which they are affixed. Leasehold improvements are depreciated on a straight-line basis over the shorter of the lease term or estimated useful life of the asset. Management tests property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable.

Construction in progress

Construction in progress represents the accumulation of project development costs and construction costs primarily related to the construction of the Company’s LNG projects. The Company capitalizes project development costs once construction of the relevant project is considered probable. Interest and other related costs incurred on debt obtained for construction of property, plant and equipment are capitalized over the shorter of the construction period or related debt term. Costs incurred for the purchase of major equipment components of the LNG projects are recognized as construction in progress upon the Company receiving or taking ownership of the equipment. No depreciation expense is recognized on construction in progress until the relevant assets are completed and placed in service in accordance with the accounting guidance.

Advance equipment and construction payments

Advance equipment and construction payments represent amounts paid to suppliers for certain major equipment components of the LNG projects that have yet to be delivered, advances toward the purchase of an LNG tanker

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

where title of the tanker does not transfer to the Company until the date of delivery, or amounts paid to contractors for services not yet performed. Pursuant to the terms of certain of our agreements, the Company is required to make payments in accordance with defined milestone payment schedules as related progress milestones are completed by the respective supplier or contractor. The construction and equipment supplier agreements also contain various terms including retainage, performance bonuses, and liquidated damages that impact the amount and timing of the recognition of the related costs. Prior to the Company receiving or taking ownership of the asset, payments are capitalized to advance equipment and construction payments at the time consideration is paid or becomes payable. The amounts are transferred to construction in progress once services are performed or the related asset is received or ownership is taken by the Company.

Project development costs

Generally, the costs incurred to develop the Company’s LNG projects or to acquire LNG tankers are treated as development expenses until management concludes that construction and completion of the relevant project or LNG tanker is probable. These costs primarily include professional fees associated with early engineering and design work, costs of securing necessary regulatory approvals and permits, and other preliminary investigation and development activities related to the projects. Management’s probability conclusion for LNG projects is primarily based on the achievement of, or ability to achieve, certain critical project development milestones, including, where appropriate, receipt of the appropriate regulatory approvals and permits, entering into LNG sales contracts with respect to an adequate amount of the anticipated nameplate capacity, securing equipment and construction contracts and securing adequate financing arrangements.

Generally, costs that are capitalized during the preliminary stage of development include land acquisition costs, certain environmental credits, leasehold improvement costs necessary for preparing the facilities for their intended use, and direct costs of construction-related activities incurred with third parties. This includes costs that are directly identifiable for the early procurement of equipment that is probable of being acquired prior to a relevant project being deemed probable of construction or completion and that have an alternative use.

For further discussion of the Company’s property, plant and equipment, see Note 6 – Property, Plant and Equipment.

Leases

We determine if an arrangement is, or contains, a lease at inception of the arrangement. When an arrangement is, or contains, a lease, we classify the lease as either an operating lease or a finance lease. Operating and finance leases are recognized on the Consolidated Balance Sheets as lease liabilities, representing the obligation to make future lease payments, and right-of-use assets, representing the right to use the underlying assets for the lease term. Operating and finance lease liabilities and right-of-use assets are generally recognized based on the present value of lease payments over the lease term. In determining the present value of lease payments, we use the implicit interest rate in the lease, if readily determinable. In the absence of a readily determinable implicit interest rate, we discount our expected future lease payments using the lessee’s incremental borrowing rate. The incremental borrowing rate is an estimate of the interest rate that a lessee would have to pay to borrow on a collateralized basis over a similar term to that of the lease term. Lease and non-lease components of an arrangement are combined in calculating the right-of-use asset and lease liability. Options to renew a lease are included in the lease term and recognized as a part of the right-of-use asset and lease liability, only to the extent they are reasonably certain to be exercised. Adjustments to lease payments due to changes in a variable index are treated as variable lease costs and recognized in the period in which they are incurred.

Operating lease expense is recognized on a straight-line basis over the lease term. Finance lease expense is recognized as the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities using the

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

effective interest method over the lease term. Leases with an initial term of 12 months or less are not recognized on the Consolidated Balance Sheets and are expensed on a straight-line basis. For further discussion, see Note 7 – Leases.

Deferred financing costs

Deferred financing costs represent debt issuance costs incurred in connection with working capital facilities and term loans which have not yet been fully drawn. Deferred financing costs are amortized on a straight-line basis to interest expense over the availability period of the working capital facility or undrawn term loans. Once a term loan is fully drawn, its associated unamortized deferred financing costs are reclassified to a contra-liability in Long-term debt, net on the Consolidated Balance Sheets and are amortized to interest expense using the effective interest method over the remaining term of the debt.

Equity method investments

Investments in non-controlled entities in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, investments are initially recognized at cost, and subsequently adjusted for our proportionate share of earnings, losses and distributions. The Company utilizes the cumulative earnings approach to determine whether distributions received from equity method investees are returns on investment or returns of investment. These investments are recognized as Equity method investments on our Consolidated Balance Sheets. For further discussion, see Note 8 – Equity Method Investments.

Rights-of-way

The Company obtains perpetual rights to construct, operate and maintain its pipelines on land owned or bodies of water controlled by third parties. The costs to obtain these rights are capitalized as indefinite-lived intangible assets in Other noncurrent assets on the Consolidated Balance Sheets. No amortization is recognized on these assets, as the rights-of-way are perpetual in nature.

Derivative instruments

The Company reflects all contracts that meet the definition of a derivative, except those designated and qualifying as normal purchase and normal sale, 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. The Company designates derivative instruments based on all available facts and circumstances.

The Company enters 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 fair value on the Consolidated Balance Sheets. Changes in fair value of derivative instruments designated as cash flow hedges are recognized in accumulated other comprehensive loss (“AOCL”) until the hedged transaction affects earnings, at which time the deferred gains and losses are reclassified to earnings. Cash flows associated with derivatives hedging capitalized interest and designated as cash flow hedges are classified as investing 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. Cash flows of the Company’s derivatives which are not designated as hedging relationships are classified as operating activities in the Consolidated Statements of Cash Flows. Derivative assets and liabilities are presented net on the Consolidated Balance Sheets when a legally enforceable master netting arrangement exists with the counterparty. For further discussion, see Note 12 – Derivatives.

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

The Company evaluates all of its financial instruments to determine if such instruments are freestanding derivatives or if they contain features that qualify as embedded derivatives. If an instrument contains more than one embedded feature that warrants separate accounting, those embedded features are bundled together as a single, compound embedded derivative that is bifurcated and accounted for separately from the host contract. Embedded derivatives are presented in the same line item of the Consolidated Balance Sheets as their host contracts. Embedded derivatives are initially recognized at fair value and marked to market at each balance sheet date with changes in fair value recognized in Loss on embedded derivative on the Consolidated Statements of Operations. For further discussion see Note 13 – Fair Value Measurements.

Accounts payable and Accrued and other liabilities

The Company recognizes invoiced amounts from our operating and construction vendors as Accounts payable on the Consolidated Balance Sheets. Accrued and other liabilities on the Consolidated Balance Sheets primarily represent amounts owed to our vendors but not yet invoiced, accrued interest, and accrued compensation costs. For further discussion, see Note 9 – Accrued and Other Liabilities.

Asset retirement obligations

The Company recognizes a liability at fair value for an asset retirement obligation (“ARO”) when the legal obligation to retire the asset has been incurred (i.e., as the asset is being constructed) and a reasonable estimate of fair value can be made. The ARO liability is classified as Other noncurrent liabilities on the Consolidated Balance Sheets with a corresponding increase to the carrying amount of the related long-lived asset. AROs are periodically adjusted to reflect changes in the estimated present value of the obligation resulting from revisions to the estimated timing or amount of the expected future cash flows. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss. For further discussion, see Note 10 – Asset Retirement Obligations.

Redeemable stock of subsidiary

Redeemable stock of subsidiary on the Consolidated Balance Sheets represents third-party interests in the net assets of the Company’s subsidiary, Calcasieu Pass Funding, LLC (“CP Funding”), resulting from the issuance of the Redeemable Preferred Units, as defined and discussed in Note 17 – Redeemable Stock of Subsidiary. The third-party has the right to redeem its interests for cash upon the occurrence of events not solely within the Company’s control, therefore the redeemable stock of subsidiary is classified outside of permanent equity, as mezzanine equity, on the Consolidated Balance Sheets. The balance is carried at its current redemption value as adjusted by the contractually stated distribution amount that is recognized in each reporting period as Net income attributable to redeemable stock of subsidiary on the Consolidated Statements of Operations.

Non-controlling interests

Non-controlling interests on the Consolidated Balance Sheets represent the portion of net assets in consolidated entities that are not owned by the Company. Non-controlling interests are recognized as a separate component of equity on the Consolidated Balance Sheets and are adjusted by the amount of earnings or other comprehensive income (loss) attributable to the non-controlling interests, distributions associated with the Convertible Preferred Units (as defined and discussed in Note 18 – Non-Controlling Interests) and changes in ownership interest. A change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

equity transaction between the controlling and non-controlling interests. Losses are attributed to the non-controlling interests even when the non-controlling interests’ basis has been reduced to zero.

Operating expenses

Cost of sales is comprised of the direct cost of producing LNG recognized as revenue. It includes the cost of purchasing and transporting natural gas used in the production of LNG, also known as feed gas, and excludes depreciation and amortization, shown separately on the consolidated statements of operations.

General and administrative expense consists primarily of costs not directly associated with the operations or development of the Company’s LNG projects or tankers, such as the Company’s corporate support functions including executive management, information technology, human resources, legal, and finance.

Development expense primarily includes costs incurred to develop a project prior to management’s conclusion that construction and completion of that project is probable as well as construction stage costs that are not capitalizable. These expenses consist primarily of engineering and design expenses and other early stage development costs.

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method. The grant-date fair value attributable to stock options is calculated based on the Black-Scholes option-pricing model and is amortized on a straight-line basis to expense over the vesting period of the award. Forfeitures are recognized as they occur. For further discussion, see Note 19 – Stock-Based Compensation.

Income taxes

Prior to the Reorganization Transactions, the Company was treated as a partnership for income tax purposes. As a result, the entity incurred no U.S. federal or state tax liability, and the taxable income of the Company was reported on the tax returns of the managing members. However, certain of its subsidiaries were subject to federal, state, local and foreign corporate income taxes. With the closing of the Reorganization Transactions, the Company is treated as a corporation for income tax purposes. The change in the tax status of the Company did not have a material impact on its income taxes.

The Company accounts for 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, the Company determines 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. The Company’s accounting policy for releasing the income tax effects from AOCL occurs on a portfolio basis.

A valuation allowance is provided for deferred income taxes if it is more-likely-than-not these items will either expire before the Company is able to realize their benefits or if future deductibility is uncertain. Additionally, the Company evaluates tax positions under a more-likely-than-not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting. For further discussion, see Note 14 – Income Taxes.

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Earnings (loss) per share

Basic net earnings (loss) per share is computed by dividing Net income (loss) attributable to common stockholders by the weighted-average number of shares of common stock outstanding during the period. Diluted net income (loss) per share is computed by giving effect to all potentially dilutive securities, including stock options outstanding. For further discussion, see Note 20 – Earnings (Loss) per Share.

Note 3 – Restricted Cash

The following table summarizes the components of restricted cash (in millions):


	December 31,
	2023		2022
Current restricted cash
Calcasieu Pass Project cash reserves ^(a)	$	520	$	391

Total current restricted cash	$	520	$	391

Noncurrent restricted cash
Plaquemines Project construction ^(b)	$	310	$	993
Calcasieu Pass Project cash reserves ^(c)		219		269
VGLNG debt service reserves		—		141

Total noncurrent restricted cash	$	529	$	1,403

(a)	Associated with pre-commercial operations LNG sales and restricted to use at the Calcasieu Pass Project.

(b)	Restricted to the payment of construction and commissioning costs for the Plaquemines Project.

(c)	Primarily associated with debt service reserves and restricted cash for construction and commissioning costs for the Calcasieu Pass Project.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the Consolidated Statements of Cash Flows (in millions):


	December 31,
	2023		2022
Cash and cash equivalents	$	4,823	$	618
Current restricted cash		520		391
Noncurrent restricted cash		529		1,403

Cash, cash equivalents and restricted cash per the Consolidated Statements of Cash Flows	$	5,872	$	2,412

Note 4 – Revenue from Contracts with Customers

The following table summarizes the disaggregation of revenue earned from contracts with customers (in millions):


	Years ended December 31,
	2023		2022		2021
LNG revenue	$	7,875	$	6,433	$	—
Other revenue		22		15		—

Total revenue	$	7,897	$	6,448	$	—

F-18

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

LNG revenue recognized during the years ended December 31, 2023 and 2022, was earned under Early Cargo Sales Agreements at prevailing market prices when executed.

LNG revenue

We have entered into numerous contracts for the sale of LNG to third-party customers. Our customers generally purchase LNG for a price which includes a fixed fee per metric million British thermal unit (“MMBtu”) of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG indexed to Henry Hub. The fixed fee component under our post-COD term SPAs is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG, plus all future adjustments to the fixed fee for inflation. Sales under our Early Cargo Sales Agreements and post-COD term SPAs also include variable consideration for contingent penalties or fees which may be due from the Company, and if so, could result in the significant reversal of revenue. Estimates for penalties or fees 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.

Transaction price allocated to future performance obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price, including variable consideration, that is allocated to performance obligations that have not yet been satisfied, excluding all performance obligations that are part of contracts that have an expected duration of one year or less (dollar amounts in millions):


	December 31, 2023
	Unsatisfied transaction price ^(a)		Weighted average timing of recognition
LNG revenue	$	190,704		20 years

(a)	The transaction price is based on the forecasted Henry Hub index as of December 31, 2023.

Significant judgments were made when estimating the transaction price allocated to future performance obligations. These include the best estimate of when our respective projects will reach COD and their post-COD sales contracts commence, which we currently expect to occur in late 2024 for our Calcasieu Pass Project and in 2026 and 2027 for the first and second phases of our Plaquemines Project, respectively, and the most likely amount of variable consideration to which we expect to be entitled upon the resolution of certain ongoing disputes with customers. These disputes are with various Calcasieu Pass post-COD term SPA customers who are asserting that the Calcasieu Pass Project is delayed in declaring COD under the respective SPAs. These disputes are subject to aggregate liability limitations of $1.4 billion under the SPAs. Certain of our customers are also disputing whether the liability limitations in our SPAs are applicable, and therefore are claiming damages in excess of the liability limitations. Our estimates of variable consideration exclude decreases to the transaction price for these contingent penalties based on our best estimate of the most likely outcome of these disputes. We expect this variability to be resolved in 2025 upon the conclusion of various arbitration proceedings.

F-19

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 5 – Inventory

The following table summarizes the components of inventory (in millions):


	December 31,
	2023		2022
LNG	$	5	$	20
Spare parts and materials		39		6

Total inventory	$	44	$	26

Note 6 – Property, Plant and Equipment

The following table presents the components of property, plant and equipment, net (in millions) and their estimated useful lives (in years):


			December 31,
	Estimated useful life		2023			2022
LNG terminal and interconnected pipeline facilities		5–27	$	6,873		$	6,811
Construction in progress		N/A		9,000			2,488
Advanced equipment and construction payments		N/A		3,617			1,325
Finance lease assets		3–11		101			91
Leasehold improvements		1–30		214			35
Land		N/A		26			10
Other		3–7		60			10

Total property, plant and equipment at cost				19,891			10,770
Accumulated depreciation and amortization				(452	)		(164	)

Total property, plant and equipment, net ^(a)			$	19,439		$	10,606

(a)	Includes $10.6 billion of Property, plant and equipment restricted to use at Plaquemines and Gator Express, which are wholly-owned consolidated VIEs.

On March 1, 2022 and June 30, 2022, management determined the first and second phase of the Plaquemines Project, respectively, were probable of construction and completion.

The following table presents depreciation expense recognized on the Company’s Consolidated Statements of Operations (in millions):


	Years ended December 31,
	2023		2022		2021
Depreciation expense	$	273	$	154	$	5

F-20

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 7 – Leases

Our leased assets consist primarily of land, tug vessels, a bridge, and office space and facilities, all of which are classified as operating leases, except for our tug vessels and bridge which are classified as finance leases.

The following table presents the line item classification of the Company’s right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):


		December 31,
	Line item	2023		2022
Right-of-use assets - operating	Right-of-use assets	$	381	$	327
Right-of-use assets - finance	Property, plant and equipment, net		101		91

Total right-of-use assets		$	482	$	418

Current operating lease liabilities	Accrued and other liabilities	$	13	$	12
Current finance lease liabilities	Accrued and other liabilities		13		9
Noncurrent operating lease liabilities	Noncurrent operating lease liabilities		383		337
Noncurrent finance lease liabilities	Other noncurrent liabilities		75		78

Total lease liabilities		$	484	$	436

The following table presents the line item classification of the Company’s lease costs (in millions):


	Line item	Years ended December 31,
	Line item	2023		2022		2021
Operating lease cost	Operating and maintenance expense	$	22	$	16	$	9
	General and administrative expense		8		5		4
	Development expense		19		15		7
Finance lease cost
Amortization of right-of-use assets	Depreciation and amortization and Property, plant and equipment, net		11		8		1
Interest on lease liabilities	Interest expense, net and Property, plant and equipment, net		6		6		1
Short-term lease cost	Cost of sales		—		35		—

Total lease cost		$	66	$	85	$	22

F-21

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Future annual minimum lease payments for operating and finance leases as of December 31, 2023 are as follows (in millions):


Years ended December 31,	Operating leases			Finance leases
2024	$	37		$	18
2025		41			15
2026		38			12
2027		33			11
2028		31			11
Thereafter		736			48

Total lease payments	$	916		$	115
Less: Interest		(520	)		(27	)

Present value of lease liabilities	$	396		$	88

The following table presents the weighted-average remaining lease term (in years) and the weighted-average discount rate for the Company’s operating leases and finance leases:


	December 31,
	2023						2022
	Operating leases			Finance leases			Operating leases			Finance leases
Weighted-average remaining lease term		25.0			8.6			24.5			10.2
Weighted-average discount rate		7.4	%		6.7	%		6.4	%		6.8	%

Note 8 – Equity Method Investments

The following table presents the Company’s equity method investment ownership interests and carrying values (dollar amounts in millions):


	December 31, 2023
Equity method investment ^(a)	Ownership interest			Carrying value
Kagami 1		19	%	$	110
Kagami 2		19	%		110
Astra 5		40	%		159
Astra 8		40	%		160

Total				$	539

(a)	These companies are VIEs in which the Company is not the primary beneficiary since it lacks the power to make significant decisions.

Kagami Companies

During the year ended December 31, 2023, the Company acquired equity interests in Project Kagami 1 Limited (“Kagami 1”) and Project Kagami 2 Limited (“Kagami 2,” and together with Kagami 1, the “Kagami Companies”). The Kagami Companies will each purchase one LNG tanker. The Company has future commitments to increase its investment in the Kagami Companies by $334 million to fund construction of the LNG tankers, which is subject to conditions precedent that have not yet been satisfied.

F-22

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Astra Companies

During the year ended December 31, 2023, the Company acquired equity interests in Astra 5 Limited (“Astra 5”) and Astra 8 Limited (“Astra 8,” and together with Astra 5, the “Astra Companies”). The Astra Companies will each purchase one LNG tanker. The Company has future commitments to increase its investment in the Astra Companies by $253 million to fund construction of the LNG tankers, which is subject to conditions precedent that have not yet been satisfied.

Note 9 – Accrued and Other Liabilities

Components of accrued and other liabilities included (in millions):


	December 31,
	2023		2022
Accrued construction and equipment costs	$	1,012	$	671
Accrued interest		230		77
Accrued natural gas purchases		164		311
Accrued compensation		134		117
Other		161		168

Total accrued and other liabilities	$	1,701	$	1,344

Note 10 – Asset Retirement Obligations

The following table summarizes the components of the Company’s asset retirement obligations (in millions):


	Years ended December 31,
	2023		2022
Beginning balance as of January 1	$	191	$	17
Liabilities incurred		112		8
Accretion expense		14		1
Revision in estimated cash flows		94		165

Ending balance as of December 31	$	411	$	191

Note 11 – Debt

The following table summarizes the Company’s outstanding debt (dollar amounts in millions):


					December 31,
	Maturity	Interest rate ^(a)			2023		2022
Fixed rate:
VGLNG 2028 Notes	June 1, 2028		8.125	%	$	2,250	$	—
VGLNG 2029 Notes ^(b)	February 1, 2029		9.500	%		3,000		—
VGLNG 2031 Notes	June 1, 2031		8.375	%		2,250		—
VGLNG 2032 Notes ^(c)	February 1, 2032		9.875	%		2,000		—
Calcasieu Pass 2029 Notes	August 15, 2029		3.875	%		1,250		1,250
Calcasieu Pass 2030 Notes	January 15, 2030		6.250	%		1,000		—
Calcasieu Pass 2031 Notes	August 15, 2031		4.125	%		1,250		1,250
Calcasieu Pass 2033 Notes	November 1, 2033		3.875	%		1,250		1,250

F-23

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


			December 31,
	Maturity	Interest rate ^(a)	2023			2022
Variable rate:
Calcasieu Pass Construction Term Loan				1,174			2,305
PL Holdings Credit Facility ^(d)				727			—
Plaquemines Construction Term Loan				4,944			1,069
VGLNG 2025 Term Loan				—			3,300
VGC 2024 Term Loan				—			380

Total outstanding debt				21,095			10,804

Less: Unamortized debt discount, premium and issuance costs				(310	)		(196	)

Total outstanding debt, net				20,785			10,608
Less: Current portion of long-term debt				(178	)		(150	)

Total long-term debt, net			$	20,607		$	10,458

(a)	Refer below for the rates associated with the respective variable rate debt instruments.

(b)	Issued in October and November 2023 at 100.167% of par.

(c)	Issued in October and November 2023 at 99.661% of par.

(d)	Refer to the credit facility discussion below for further information.

The aggregate contractual annual maturities for outstanding debt as of December 31, 2023 are as follows (in millions):


Years ended December 31,	Contractual maturities
2024	$	178
2025		917
2026		806
2027		238
2028		2,606
Thereafter		16,350

Total	$	21,095

VGLNG Senior Secured Notes

The VGLNG 2028 Notes, VGLNG 2029 Notes, VGLNG 2031 Notes, and VGLNG 2032 Notes are collectively referred to as the “VGLNG Senior Secured Notes”. The VGLNG Senior Secured Notes are secured on a pari passu basis by a first-priority security interest in substantially all of the existing and future assets of VGLNG and the future guarantors, if any. In addition, VGLNG has pledged its membership interests in certain material direct subsidiaries as collateral to secure its obligations under the VGLNG Senior Secured Notes. VGLNG may redeem all or part of the VGLNG Senior Secured Notes at specified prices set forth in the respective governing indenture agreements, plus accrued interest, if any, as of the date of the redemption.

Calcasieu Pass Senior Secured Notes

The Calcasieu Pass 2029 Notes, Calcasieu Pass 2030 Notes, Calcasieu Pass 2031 Notes, and Calcasieu Pass 2033 Notes are collectively referred to as the “Calcasieu Pass Senior Secured Notes”. The obligations of Calcasieu

F-24

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Pass under the Calcasieu Pass Senior Secured Notes are guaranteed by TransCameron and secured on a pari passu basis by a first-priority security interest in the assets that secure the Calcasieu Pass Credit Facility. Calcasieu Pass may redeem all or part of the Calcasieu Pass Senior Secured Notes at specified prices set forth in the respective governing indenture agreements, plus accrued interest, if any, as of the date of the redemption.

Credit Facilities

Below is a summary of the Company’s committed credit facilities outstanding as of December 31, 2023 (in millions):


	Calcasieu Pass Credit Facility ^(a)								Plaquemines Credit Facility ^(d)
	Calcasieu Pass Construction Term Loan			Calcasieu Pass Working Capital Facility			PL Holdings Credit Facility ^(c)		Plaquemines Construction Term Loan			Plaquemines Working Capital Facility
Original facility size	$	5,477			300		$	1,665	$	8,459		$	1,100
Incremental commitments		—			255			—		4,489			1,000
Less:
Outstanding balances		1,174			—			727		4,944			—
Commitments prepaid or terminated		4,303			—			938		—			—
Letters of credit issued		—			339			—		—			840

Available commitments	$	—		$	216		$	—	$	8,004		$	1,260

Priority ranking		Senior secured			Senior secured			Secured		Senior secured			Senior secured
Interest rate on outstanding balances		SOFR^(b) + 2.375% to 2.875%			SOFR^(b) + 2.375% to 2.875%			SOFR + 5.100% to 5.250%		SOFR + 1.975% to 2.625%			SOFR + 1.975% to 2.625%
		or			or			or		or			or
		base rate + 1.375% to 1.875%			base rate + 1.375% to 1.875%			base rate + 4.000%		base rate + 0.875% to 1.375%			base rate + 0.875% to 1.375%
Commitment fees on undrawn balance		0.831	%		0.919	%		—		0.656	%		0.656	%
Maturity date		August 19, 2026			August 19, 2026			March 10, 2025		May 25, 2029			May 25, 2029

(a)	The obligations of Calcasieu Pass as the borrower are guaranteed by TransCameron and secured by a first-priority lien on substantially all of the assets of Calcasieu Pass and TransCameron, as well as all of the membership interests in those companies.

(b)

During the year ended December 31, 2023, the Calcasieu Pass Credit Facility was modified to transition its variable rate interest from the London Interbank Offered Rate (“LIBOR”) to the U.S. Secured Overnight Financing Rate (“SOFR”). Calcasieu Pass elected to apply the expedient available under ASC 848, Reference Rate Reform to account for the modification as a continuation of the existing contract and not a debt modification.

(c)

The obligations of Plaquemines LNG Holdings, LLC (“PL Holdings”), a wholly-owned indirect subsidiary of Venture Global, are secured on a pari passu basis by a first-priority security interest in substantially all of the existing and future assets of PL Holdings. In addition, PL Holdings has pledged its membership interests as collateral to secure its obligations under the PL Holdings Credit Facility.

(d)	The obligations of Plaquemines as the borrower are guaranteed by Gator Express and secured by a first-priority lien on substantially all of the assets of Plaquemines and Gator Express, as well as all of the membership interests in those companies.

F-25

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Debt covenants

The Company’s debt instruments contain certain customary affirmative and negative covenants that among other things, limit our ability to incur additional indebtedness, create liens, dispose of assets, or pay dividends, distributions or other restricted payments. The Calcasieu Pass Credit Facility and the Plaquemines Credit Facility both include a financial covenant that requires the borrower to maintain a historical debt service coverage ratio of at least 1.15:1 as of the end of any fiscal quarter following the first term loan repayment date. As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective debt obligations.

The Calcasieu Pass and Plaquemines projects are restricted from making distributions under the agreements governing their respective indebtedness generally until, among other requirements, they have established the appropriate reserves and historical and projected debt service reserves. The restricted net assets of our consolidated subsidiaries was approximately $5.8 billion as of December 31, 2023.

Interest expense on debt

The following table presents the total interest expense incurred on the Company’s debt and other instruments (in millions):


	Years ended December 31,
	2023			2022			2021
Stated interest	$	1,038		$	562		$	226
Amortization of debt discounts and issuance costs		138			162			67
Other interest and fees		114			95			22

Total interest cost		1,290			819			315
Capitalized interest		(649	)		(227	)		(263	)

Total interest expense, net	$	641		$	592		$	52

Note 12 – Derivatives

Interest rate swaps

The Company has entered into interest rate swaps to mitigate its exposure to variability in interest payments associated with certain variable rate debt.

During the year ended December 31, 2023, the Company received $83 million, net, from the settlement of a portion of the interest rate swaps associated with the Calcasieu Pass Credit Facility and the Plaquemines Credit Facility. In addition, the Company received $12 million from the full settlement of the interest rate swaps associated with the VGLNG 2025 Term Loan. Of the settlements, $41 million was associated with the termination of Calcasieu Pass Credit Facility interest rate swaps designated as cash flow hedges and therefore was deferred in AOCL and will be recognized in earnings at the time the originally forecasted hedged transaction impacts earnings. The Company did not re-designate the remaining notional amounts of the interest rate swaps previously designated as cash flow hedges.

F-26

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the Company’s outstanding interest rate swaps (dollar amounts in millions):


											Outstanding notional
											December 31,
Debt instrument	Latest maturity			Receive variable rate		Pay fixed rate^(c)			Maximum notional		2023		2022
Plaquemines Credit Facility		2046	^(a)		Compounding SOFR		2.49	%	$	10,204	$	5,059	$	2,691
Calcasieu Pass Credit Facility		2036	^(b)		Compounding SOFR		2.55	%		1,142		1,142		2,195
VGLNG 2025 Term Loan		2025			1-month LIBOR and Compounding SOFR		2.04	%		—		—		250

									$	11,346	$	6,201	$	5,136

(a)	Subject to mandatory early termination provisions under which certain interest rate swaps will settle at their fair values in May 2029.

(b)	Subject to mandatory early termination provisions under which certain interest rate swaps will settle at their fair values in August 2026.

(c)	Represents a weighted-average fixed rate based on the maximum notional.

The following table summarizes the fair value (in millions), classification and hedge designation of the Company’s derivatives on the Consolidated Balance Sheets as of December 31, 2023 and 2022:


		December 31,
		2023						2022
	Balance sheet location	Designated		Non-designated		Total		Designated		Non-designated		Total
Assets
Interest rate swaps	Derivative assets	$	—	$	164	$	164	$	25	$	121	$	146
Interest rate swaps	Noncurrent derivative assets		—		899		899		61		912		973

Total assets		$	—	$	1,063	$	1,063	$	86	$	1,033	$	1,119

Liabilities
Interest rate swaps	Accrued and other liabilities	$	—	$	1	$	1	$	—	$	1	$	1
Interest rate swaps	Other noncurrent liabilities		—		6		6		—		20		20

Total liabilities		$	—	$	7	$	7	$	—	$	21	$	21

F-27

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the pre-tax effects of the Company’s derivative instruments recognized in AOCL and earnings (in millions):


	Line item	Years ended December 31,
	Line item	2023			2022			2021
Designated as hedging instruments
Gains (losses) recognized in AOCL
Interest rate swaps	Change in fair value	$	(10	)	$	113		$	70
Reclassifications of losses from AOCL into earnings
Interest rate swaps	Depreciation and amortization		2			1			—
Interest rate swaps	Interest expense, net		3			9			—

Total		$	5		$	10		$	—

Not designated as hedging instruments — recognized in earnings
Interest rate swaps	Gain on derivatives, net	$	174		$	1,212		$	38
Embedded derivative	Gain (loss) on embedded derivative		—			(14	)		12

Approximately $14 million is expected to be reclassified from AOCL as a reduction to earnings within the next twelve months.

The following table presents the gross and net fair value of the Company’s outstanding interest rate swaps (in millions):


	December 31,
	2023								2022
	Gross balance			Balance subject to netting		Net balance			Gross balance			Balance subject to netting			Net balance
Derivative assets	$	1,063		$	—	$	1,063		$	1,132		$	(13	)	$	1,119
Derivative liabilities		(7	)		—		(7	)		(34	)		13			(21	)

Credit-risk related contingent features

The interest rate swap agreements contain cross default provisions whereby if the Company were to default on certain indebtedness, it could also be declared in default on its derivative obligations and may be required to net settle the outstanding derivative liability positions with its counterparties. As of December 31, 2023, the Company had not posted any collateral related to these agreements and was not in breach of any agreement provisions. The aggregate fair value of our derivative instruments with credit-risk related contingent features in a net liability position was $7 million as of December 31, 2023.

F-28

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 13 – Fair Value Measurements

The following table presents the Company’s financial assets and liabilities measured at fair value on a recurring basis and indicates their levels within the fair value hierarchy (in millions):


	December 31,
	2023								2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Money market funds ^(a)	$	3,391	$	—	$	—	$	3,391	$	378	$	—	$	—	$	378
Interest rate swaps ^(b)		—		1,063		—		1,063		—		1,132		—		1,132

Total	$	3,391	$	1,063	$	—	$	4,454	$	378	$	1,132	$	—	$	1,510

Liabilities
Interest rate swaps ^(c)	$	—	$	7	$	—	$	7	$	—	$	34	$	—	$	34

Total	$	—	$	7	$	—	$	7	$	—	$	34	$	—	$	34

(a)	Included in Cash and cash equivalents on the Consolidated Balance Sheets.

(b)	Included in Derivative assets and Noncurrent derivative assets on the Consolidated Balance Sheets.

(c)	Included in Accrued and other liabilities and Other noncurrent liabilities on the Consolidated Balance Sheets.

Interest rate swaps

The fair values of the Company’s interest rate swaps are classified as Level 2 and determined using a discounted cash flow method that incorporates observable inputs. The fair value calculation includes a credit valuation adjustment and forward interest rate curves for the same periods of the future maturity dates of the interest rate swaps. For further discussion, see Note 12 – Derivatives.

Level 3 unobservable inputs

In June 2019, VGLNG issued a $460 million senior convertible note that contained embedded features subject to derivative accounting (the “2024 Convertible Note”). The fair value of the embedded derivative was determined as the difference between the fair value of the 2024 Convertible Note with and without the embedded derivative using a discounted cash flow model under which the future probability-weighted settlement scenarios were discounted from their respective potential settlement dates to the valuation date. The 2024 Convertible Note and its associated embedded derivative were modified and fully settled in December 2022.

F-29

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth a reconciliation of changes in the fair value of the Company’s net derivative instruments measured at fair value on a recurring basis using Level 3 inputs for the year ended December 31, 2022 (in millions). There were no derivative instruments measured at fair value using Level 3 inputs during the year ended December 31, 2023.


	Year ended December 31, 2022
	Interest rate swaps			Embedded derivative			Total
Beginning balance as of January 1	$	(57	)	$	(162	)	$	(219	)
Issuances ^(a)		—			(16	)		(16	)
Settlements		—			192			192
Total realized and unrealized gain (loss):
Included in earnings		190			(14	)		176
Transfers of assets out of Level 3 ^(b)		(133	)		—			(133	)

Ending balance as of December 31	$	—		$	—		$	—

Unrealized gain included in earnings	$	190		$	—		$	190

(a)	Represents interest paid-in-kind on the 2024 Convertible Note attributed to the embedded derivative.

(b)	Represents the transfer of Plaquemines Credit Facility interest rate swaps to Level 2 upon the removal of a certain deal contingent feature.

Other financial instruments

The following table presents the fair value of the Company’s outstanding debt instruments in the Consolidated Balance Sheets (in millions):


			December 31,
	Level		2023		2022
Fixed rate debt		1	$	14,098	$	3,176
Variable rate debt ^(a)		2		6,845		7,054

(a)	Carrying value approximates estimated fair value.

Note 14 – Income Taxes

The Company is a taxpayer in multiple jurisdictions within the U.S. The Company is also a taxpayer in certain international jurisdictions due to its limited operations outside the U.S.

F-30

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Income tax expense consisted of the following (in millions):


	Years ended December 31,
	2023			2022		2021
Current
Federal	$	133		$	—	$	—
State		6			—		—
Foreign		—			1		—

Total current income tax expense	$	139		$	1	$	—

Deferred
Federal		681			441		—
State		(4	)		5		—

Total deferred income tax expense		677			446		—

Total income tax expense	$	816		$	447	$	—

The following is a reconciliation of the statutory federal income tax rate to the effective tax rate:


	Years ended December 31,
	2023			2022			2021
U.S. federal statutory tax rate		21.0	%		21.0	%		21.0	%
State tax rate, net of federal tax benefit		(0.3	)%		(0.5	)%		3.4	%
Change in valuation allowance		0.8	%		(11.7	)%		(11.5	)%
Change in tax rate		(0.2	)%		(0.2	)%		(10.7	)%
163(l) interest expense		—	%		4.2	%		(5.0	)%
Guaranteed payment		(0.3	)%		(0.3	)%		2.7	%
Foreign derived intangible income (“FDII”) deduction		(1.8	)%		—	%		—	%
Stock-based compensation		(0.8	)%		—	%		—	%

Effective tax rate		18.4	%		12.5	%		(0.1	)%

Significant components of deferred tax assets and liabilities are included in the table below (in millions):


	December 31,
	2023			2022
Deferred tax assets
Lease liabilities	$	111		$	102
Net operating loss carryforwards		174			1,063
Stock-based compensation		29			28
Property, plant and equipment		139			—
Accrued expenses		31			30
Asset retirement obligations		70			20
Other deferred tax assets		10			23

Total deferred tax assets		564			1,266
Deferred tax liabilities
Derivative assets		(251	)		(270	)
Outside basis in CP Holdings		(1,256	)		(1,304	)

F-31

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


	December 31,
	2023			2022
Property, plant and equipment		—			(4	)
Right-of-use assets		(107	)		(96	)
Other deferred tax liabilities		(3	)		(3	)

Total deferred tax liabilities		(1,617	)		(1,677	)
Less: Valuation allowance		(96	)		(63	)

Net deferred tax liabilities	$	(1,149	)	$	(474	)

As of December 31, 2023, the Company had accumulated an outside basis taxable temporary difference for its investment in CP Holdings of $5.9 billion. This outside basis amount is primarily comprised of differences between the GAAP and tax basis of CP Holdings’ property, plant and equipment.

As of December 31, 2023, the Company had accumulated federal net operating loss carryforwards of $367 million with an indefinite carryforward period. As of December 31, 2023, the Company also had accumulated state net operating loss carryforwards of approximately $1.7 billion (after the application of state apportionment factors), of which $42 million will expire by 2037. Utilization of these net operating losses may be limited when there is an ownership change as defined by Section 382 of the Internal Revenue Code. As of December 31, 2023, the Company did not believe any of its net operating losses were limited under these rules.

Net operating losses may also be limited when there is a separate return limitation year (“SRLY”). These rules generally limit the use of net operating loss carryforwards to the amount of taxable income that the net operating loss-producing entity contributes to the consolidated group’s taxable income. Net operating losses subject to the SRLY rules may also be subject to Section 382 limitations. Of the $367 million federal net operating loss carryforward as of December 31, 2023, $42 million is currently subject to the SRLY rules.

The Company maintains a valuation allowance against its federal deferred tax assets related to its SRLY tax attributes and its state deferred tax assets for which it continues to believe the more-likely-than-not recognition threshold has not been met. The Company’s valuation allowances increased by $33 million during the year to $96 million as of December 31, 2023. This increase was primarily due to state valuation allowance activity.

As of December 31, 2023 and 2022, the Company had no unrecognized tax benefits and did not recognize any interest or penalties during those respective periods.

The Company remains subject to examination of its U.S. federal and state income tax returns for the tax years ended 2019 through 2023. Tax authorities may have the ability to review and adjust carryover tax attributes that were generated prior to these periods.

On August 16, 2022, the Inflation Reduction Act of 2022 (“IRA”) was enacted in the U.S. The IRA included a 15% alternative minimum tax on the “adjusted financial statement income” of certain corporations and a 1% excise tax on stock repurchases, both of which became effective in 2023. These provisions did not have a material impact to the Company’s financial statements.

The Organization Economic Co-operation and Development (“OECD”) introduced Base Erosion and Profit Shifting (“BEPS”) Pillar 2 rules that impose a global minimum tax rate of 15%. Numerous countries, including European Union member states, have enacted legislation to be effective as early as January 1, 2024, with general implementation of a global minimum tax by January 1, 2025. The Company is continuing to evaluate the potential impact on its consolidated financial statements, as further guidance becomes available.

F-32

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 15 – Commitments and Contingencies

The following is a schedule of the Company’s future minimum commitments as of December 31, 2023 (in millions):


Years ended December 31,	Natural gas supply		Firm transportation		LNG tankers		Other		Total
2024	$	1,166	$	145	$	141	$	59	$	1,511
2025		1,781		352		632		34		2,799
2026		1,457		400		288		9		2,154
2027		1,115		400		—		5		1,520
2028		880		400		—		5		1,285
Thereafter		962		6,288		—		21		7,271

Total	$	7,361	$	7,985	$	1,061	$	133	$	16,540

Natural gas supply

The Company has entered into natural gas forward purchase contracts for the supply of feed gas to the Calcasieu Pass Project and the Plaquemines Project. The Company intends to take physical delivery of the contracted quantities through March 2030, at a purchase price indexed to the Henry Hub price for natural gas. The Company has designated the natural gas forward contracts as normal purchase and normal sale transactions exempted from derivative accounting treatment.

Firm transportation agreements

The Company has entered into long-term natural gas firm transportation service agreements with various interstate pipeline companies to secure the natural gas transportation requirements for the Calcasieu Pass Project and the Plaquemines Project through June 2045.

LNG tankers

The Company has entered into shipbuilding agreements for the construction of five LNG tankers, excluding commitments for our equity method investments discussed in Note 8 – Equity Method Investments. The LNG tankers will be used to provide shipping capabilities to our LNG projects upon their deliveries beginning in July 2025.

Litigation

The Company is involved in certain claims, suits, and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company. This could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2023. Contingencies where losses are reasonably possible primarily relate to disputes with contractors. Damages from our disputes with contractors could range from zero up to approximately $200 million. See Note 4 – Revenue from Contracts with Customers, for further discussion of the disputes with customers.

F-33

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 16 – Equity

During the year ended December 31, 2022, the Company’s consolidated subsidiary, VGLNG, repurchased 55,000 shares of its Series B common stock and 23,700 shares of its Series C common stock for $1.4 billion. This was recognized as a $1.0 billion and $0.4 billion reduction to members’ capital and non-controlling interests, respectively. In addition, during the year ended December 31, 2023, prior to the Reorganization Transactions, VGLNG repurchased 5,000 shares of its Series B common stock and 81,896 shares of its Series C common stock for $1.6 billion. This was recognized as a $1.2 billion and $0.4 billion reduction to stockholders’ equity and non-controlling interests, respectively.

In September 2023, in connection with the Reorganization Transactions, Venture Global completed the 2023 Merger whereby Legacy VG Partners merged with and into Venture Global, with VG Partners receiving 435,500 shares of Venture Global’s Class A common stock in exchange for its equity interests in Legacy VG Partners.

In addition, as part of the Reorganization Transactions, the VGLNG non-controlling shareholders holding 84,272 shares of VGLNG’s Series C common stock received 84,272 shares of Venture Global’s Class A common stock, in a one-for one exchange.

Upon completion of the Reorganization Transactions in September 2023, all shares of VGLNG’s Series A, Series B and Series C common stock were owned and subsequently retired by the Company, resulting in a $2.0 billion reduction to retained earnings.

The following table summarizes the number of shares of the Company’s preferred stock and common stock authorized for issuance and outstanding by class as of December 31, 2023:


	Authorized		Outstanding
Preferred stock		1,000,000		—
Class A common stock		1,000,000		519,772
Class B common stock		1,000,000		—

Each class of stock is subject to a shareholders’ agreement. The holders of the Class A common stock common stockholders are entitled to one vote per share.

Note 17 – Redeemable Stock of Subsidiary

In August 2019, the Company issued nine million redeemable preferred units in CP Funding with an initial face value of $100 per preferred unit (the “Redeemable Preferred Units”). The Redeemable Preferred Units are redeemable at the Company’s option or, following the eighth anniversary of the date of issuance, to the extent the Company has available cash as defined within CP Funding’s ownership agreement. The Redeemable Preferred Units have an aggregate liquidation preference of $900 million plus accrued or paid-in-kind distributions and an additional premium if liquidation occurs during the first six years after the date of issuance or if redemption occurs during years four through six after the date of issuance. The Redeemable Preferred Units are not convertible to common units or any other classes of interests and have no voting rights, except with respect to certain matters that require approval from the holders of the Redeemable Preferred Units.

The Redeemable Preferred Units pay cumulative, quarterly distributions at an initial rate of 10.0% per annum. Distributions can be paid in cash or in-kind by increasing the face value of the Redeemable Preferred Units. The distribution rate increases by 0.5% upon the eighth anniversary of the date of issuance and every six months thereafter up to a maximum rate of 15.0% per annum. Distributions paid in-kind following COD for the Calcasieu Pass Project are subject to an additional 1.0% distribution.

F-34

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The Redeemable Preferred Units are carried at their redemption value and presented as Redeemable stock of subsidiary on the Consolidated Balance Sheets. The following table summarizes the change in Redeemable stock of subsidiary on the Consolidated Balance Sheets (in millions):


	Years ended December 31,
	2023		2022
Beginning balance as of January 1	$	1,255	$	1,137
Paid-in-kind distributions ^(a)		130		118

Ending balance as of December 31	$	1,385	$	1,255

(a)	Presented as Net income attributable to redeemable stock of subsidiary on the Consolidated Statements of Operations.

Note 18 – Non-Controlling Interests

VGLNG

During the years ended December 31, 2023 and 2022, and prior to the Reorganization Transactions, VGLNG repurchased shares of its Series B and Series C common stock. This was recognized as a reduction to stockholders’ equity and non-controlling interests. As part of the NCI Acquisition, the remaining non-controlling VGLNG shareholders exchanged their shares of common stock of VGLNG for shares of Class A common stock of Venture Global. See Note 1 – The Company and Note 16 – Equity for further discussion.

CP Holdings

In August 2019, CP Holdings issued four million convertible preferred units in CP Holdings with an initial face value of $100 per preferred unit (the “Convertible Preferred Units”). The Convertible Preferred Units are convertible into Class B common units of CP Holdings based on a prescribed conversion ratio. Conversion is automatic upon COD of the Calcasieu Pass Project, or, at the option of the holder of the Convertible Preferred Units, upon liquidation or change of control in CP Holdings or its subsidiaries. On a liquidation or change of control event, the holder of the Convertible Preferred Units also has the option to redeem the Convertible Preferred Units at the aggregate liquidation preference of $400 million plus accrued distributions.

The Convertible Preferred Units pay a cumulative quarterly distribution at an initial rate of 10.0% per annum recognized as Net income attributable to non-controlling interests. Distributions can be paid in cash or in-kind by increasing the face value of the Convertible Preferred Units prior to conversion. The distribution rate increases by 0.5% upon the eighth anniversary of the date of issuance and every six months thereafter up to a maximum rate of 15.0% per annum. The conversion ratio of the Convertible Preferred Units was approximately 23% of CP Holdings’ total outstanding common units as of December 31, 2023.

The following table summarizes the change in the Convertible Preferred Units (dollar amounts in millions):


	Years ended December 31,
	2023			2022		2021
Beginning balance as of January 1	$	547		$	494	$	447
Net income attributable to non-controlling interests		57			53		47
Distributions		(29	)		—		—

Ending balance as of December 31	$	575		$	547	$	494

F-35

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 19 – Stock-Based Compensation

In connection with the Reorganization Transactions, on September 25, 2023, the Company adopted the 2023 Stock Option Plan (the “2023 Plan”) which replaced the 2014 Stock Option Plan (the “Predecessor Plan”). Under the 2023 Plan, options outstanding to purchase 86,664 shares of VGLNG’s Series A common stock were automatically converted, on a one-for-one basis, in accordance with and pursuant to the terms of the Predecessor Plan, into options to purchase shares of the Company’s Class A common stock subject to the terms and conditions of the 2023 Plan. There are no other differences between the terms and conditions of the 2023 Plan and the Predecessor Plan. The 2023 Plan provides for the issuance of 95,000 shares of the Company’s Class A common stock.

Stock option activity

A summary of stock-based compensation activity for the years ended December 31, 2023, 2022 and 2021 is presented below:


	Options			Weighted average exercise price		Exercise price range		Weighted average remaining contractual life (in years)		Aggregate intrinsic value (in millions)
Outstanding at December 31, 2020		73,133		$	3,430	$	1 to $7,000
Granted		5,700		$	7,868	$	7,000 to $10,000
Exercised		—
Forfeited or expired		(360	)	$	5,571	$	3,568 to $7,000

Outstanding at December 31, 2021		78,473		$	3,743	$	1 to $10,000
Granted		9,000		$	14,933	$	12,000 to $15,300
Exercised		—
Forfeited or expired		(2,557	)	$	3,193	$	2,000 to $7,000

Outstanding at December 31, 2022		84,916		$	4,945	$	1 to $15,300
Granted		700		$	18,814	$	18,000 to $23,700
Exercised		—
Forfeited or expired		(17,820	)	$	1,286	$	1 to $7,000

Outstanding at December 31, 2023		67,796		$	6,106	$	2.50 to $23,700		4.9	$	1,566
Exercisable at December 31, 2023		58,265		$	5,130	$	2.50 to $23,700		4.5	$	1,402

The Black-Scholes fair value of the stock options granted during the years ended December 31, 2023, 2022 and 2021 was determined using the following assumptions:

Years ended December 31,

2023

2022

2021

Weighted
average

Range

Weighted
average

Range

Weighted
average

Range

Expected life ^(a)

6.1 years

Risk-free interest rate ^(b)

4.1%

3.6% to 4.6%

3.0%

2.4% to 4.0%

1.1%

1.0% to 1.4%

Expected volatility ^(c)

40.2%

40.1% to 40.4%

37.3%

37.1% to 38.6%

38.8%

37.7% to 38.9%

Expected dividend yield

— %

(a)	Computed using the simplified method based on the mid-point between the vesting and contractual terms since the Company did not have sufficient historical information to estimate the expected life.

F-36

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(b)	The risk-free rate is based on U.S. Treasury bonds issued with similar maturity dates to the expected life of the grant.

(c)	Expected volatility is based on a weighted measure of historical, implied and expected volatility of comparable companies in the Company’s industry sector.

The options granted during the years ended December 31, 2023, 2022 and 2021, were granted at exercise prices equal to the fair market value of VGLNG’s Series A common stock on the respective grant dates. No options were granted under the new 2023 Plan during the year ended December 31, 2023. The options have a 10-year term and vest in equal quarterly installments over a four-year service period, subject to continued service through each vesting date. The weighted average grant-date fair value of options granted during the years ended December 31, 2023, 2022, and 2021 were $8,594, $6,197, and $3,048, respectively.

The classification of stock-based compensation expense by line item in the Company’s Consolidated Statements of Operations is as follows (in millions):


	Years ended December 31,

	2023		2022		2021
General and administrative expense	$	19	$	25	$	20
Operating and maintenance expense		6		—		—
Development expense		3		—		—

Total stock-based compensation expense	$	28	$	25	$	20

A tax benefit of $28 million related to stock-based compensation expense was recognized during the year ended December 31, 2023. No income tax benefit related to stock-based compensation expense was recognized during the years ended December 31, 2022 and 2021.

During the year ended December 31, 2023, the Company paid $152 million to settle a subset of fully vested options. The cash settlement did not constitute a modification of the awards or result in additional stock-based compensation expense.

As of December 31, 2023, there remained $47 million of total unrecognized compensation cost related to non-vested stock-based compensation grants. The Company expects this expense to be recognized over a weighted-average period of approximately 2.2 years.

F-37

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 20 – Earnings (Loss) per Share

The following table sets forth the computation of net income (loss) per share attributable to the Company’s Class A common stock outstanding (in millions, except share and per share amounts). The number of weighted average shares outstanding prior to the 2023 Merger were calculated based on the one-for-one exchange ratio of 435,500 shares of the Company’s Class A common stock issued to VG Partners in exchange for 100% of the Legacy VG Partners members’ equity interests in connection with the 2023 Merger:


	Years ended December 31,
	2023		2022		2021
Net income (loss)	$	3,616	$	3,097	$	(436	)
Less: Net income attributable to redeemable stock of subsidiary		130		118		107
Less: Net income (loss) attributable to non-controlling interests		805		1,121		(187	)

Net income (loss) attributable to common stockholders	$	2,681	$	1,858	$	(356	)

Weighted average shares of common stock outstanding
Basic		457,896		435,500		435,500
Dilutive stock options outstanding ^(a)		16,137		—		—

Diluted		474,033		435,500		435,500

Net income (loss) attributable to common stockholders per share—basic	$	5,855	$	4,266	$	(817	)
Net income (loss) attributable to common stockholders per share—diluted	$	5,656	$	4,266	$	(817	)

(a)	Venture Global had no outstanding stock options prior to the adoption of the 2023 Plan in September 2023. See Note 19 – Stock-Based Compensation for further discussion.

Note 21 – Related Parties

The Company has a management services agreement with VG Partners. The Company incurred $2 million in connection with this agreement during the year ended December 31, 2023, which was recognized as General and administrative expense on the Consolidated Statements of Operations.

F-38

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 22 – Supplemental Cash Flow Information

The following table sets forth supplemental disclosure of cash flow information (in millions):


	Years ended December 31,

	2023		2022		2021
Accrued purchases of property, plant and equipment	$	1,248	$	763	$	308
Cash paid for interest, net of amounts capitalized		368		220		1
Asset retirement obligation additions and revisions		206		173		10
Cash paid for income taxes		127		—		—
Paid-in-kind distribution on redeemable stock of subsidiary		130		118		107
Paid-in-kind distribution on non-controlling interests		28		52		48
Paid-in-kind interest on debt		37		78		71
Accrued distribution to non-controlling interests		15		—		—
Cash paid for operating leases		45		29		9
Right-of-use assets in exchange for new operating lease liabilities		90		61		139
Right-of-use assets in exchange for new finance lease liabilities		10		1		90

Note 23 – Segment Information

The Company has five operating segments, including our four LNG projects – the Calcasieu Pass Project, the Plaquemines Project, the CP2 LNG Project and the Delta LNG Project – and Shipping. Each LNG project operating segment 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. The Company’s chief operating decision maker (“CODM”) is the Company’s Chief Executive Officer. The CODM allocates resources, assesses performance and manages the business according to these five operating segments. The Company’s performance is evaluated based on income (loss) from operations of the respective segment.

The Company has three reportable segments, the Calcasieu Pass Project, the Plaquemines Project, and the CP2 LNG Project. The Delta LNG Project and Shipping are not quantitatively material for reporting purposes and as such, have been combined with corporate activities as Corporate and other.

Activities reported in Corporate and other include immaterial operating segments, costs which are overhead in nature and not directly associated with the LNG projects and shipping activities, including certain general and administrative and marketing expenses, and inter-segment eliminations.

The Company attributes revenues from external customers by selling location. All revenue and the majority of long-lived assets were attributed to or located in the United States. Certain assets related to our shipping activities are located outside the United States.

F-39

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following tables present financial information by segment and a reconciliation of the Company’s segment Income (loss) from operations to Income before income tax expense on the Consolidated Statements of Operations for the periods indicated (in millions):


	Years ended December 31,
Revenue	2023		2022		2021
Calcasieu Pass Project	$	7,897	$	6,448	$	—


	Years ended December 31,
Income (loss) from operations	2023			2022			2021
Calcasieu Pass Project	$	5,598		$	4,042		$	(85	)
Plaquemines Project		(187	)		(269	)		(158	)
CP2 LNG Project		(362	)		(34	)		(15	)
Corporate and other		(199	)		(184	)		(79	)

Total income (loss) from operations		4,850			3,555			(337	)

Interest income		172			18			—
Interest expense, net		(641	)		(592	)		(52	)
Gain on derivatives, net		174			1,212			38
Gain (loss) on embedded derivative		—			(14	)		12
Loss on financing transactions		(123	)		(635	)		(97	)

Income (loss) before income tax expense	$	4,432		$	3,544		$	(436	)


	Total assets
As of December 31,	2023		2022
Calcasieu Pass Project	$	7,571	$	7,652
Plaquemines Project		12,734		6,174
CP2 LNG Project		1,359		21
Corporate and other		6,799		1,250

Total	$	28,463	$	15,097


	Capital expenditures						Depreciation and amortization
Years ended December 31,	2023		2022		2021		2023		2022		2021
Calcasieu Pass Project	$	98	$	1,666	$	1,970	$	256	$	144	$	2
Plaquemines Project		6,351		2,948		70		—		—		—
CP2 LNG Project		831		—		—		—		—		—
Corporate and other		875		100		39		21		14		4

Total	$	8,155	$	4,714	$	2,079	$	277	$	158	$	6

F-40

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the Company’s revenue from individual external customers that were 10% or greater than total revenue:


	Years ended December 31,
	2023			2022			2021
Customer A		33	%		19	%		*
Customer B		17	%		12	%		*
Customer C		13	%		*			*
Customer D		11	%		*			*
Customer E		*			19	%		*
Customer F		*			13	%		*
Customer G		*			12	%		*

(*)	Less than 10%.

Note 24 – Recent Accounting Pronouncements

The following table provides a description of recently issued accounting pronouncements that have not yet been adopted by the Company as of December 31, 2023. Accounting pronouncements not listed below were assessed and determined to not have a material impact to the Company’s consolidated financial statements.


Standard	Description	Effect on our Consolidated Financial Statements

ASU 2023-07, Segment Reporting (Topic 280)	In November 2023, the FASB issued ASU 2023-07, which improves reportable segment disclosure requirements. This requires disclosure about significant segment expenses regularly provided to the CODM, extending certain annual disclosures to interim periods, clarifying that single reportable segment entities must comply with ASC 280, permitting more than one measure of segment profit or loss to be reported under certain conditions, and disclosing the title and position of the CODM. The standard is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The standard should be applied on a retrospective basis.	The Company is currently evaluating the impact on our financial statement disclosures.

ASU 2023-09, Income Taxes (Topic 740)	In December 2023, the FASB issued ASU 2023-09, which enhances tax- related disclosures by requiring public business entities to disclose a tabular reconciliation, using both percentages and amounts, broken into specific categories with certain reconciling items at or above 5% of the statutory (i.e., expected) tax, further broken out by nature and/or jurisdiction;	The Company is currently evaluating the impact on our financial statement disclosures.

F-41

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Standard

Description

Effect on our Consolidated Financial
Statements

for all other entities, qualitative disclosure of the nature and effect of significant reconciling items by specific categories and individual jurisdictions; and income taxes paid (net of refunds received), broken out between federal (national), state/local and foreign, and amounts paid to an individual jurisdiction when 5% or more of the total income taxes paid.

The standard is effective for fiscal years beginning after December 15, 2024, and interim periods within fiscal years beginning after December 15, 2025. Early adoption is permitted. The standard should be applied on a prospective basis, and retrospective application is permitted.

Note 25 – Subsequent Events

Management has evaluated subsequent events after the balance sheet date and through the date of issuance of the consolidated financial statements, February 22, 2024, for appropriate accounting and disclosure. The Company has determined that there were no such events that warrant disclosure or recognition in the consolidated financial statements except for the following:

On January 26, 2024, the DOE announced a temporary pause on pending approvals of LNG exports to non-FTA nations so it can review the analysis used to determine whether the export of LNG is in the public interest. Under the Natural Gas Act, the DOE is required to issue an order authorizing LNG exports upon application unless, after opportunity for hearing, it finds that the proposed exports will not be consistent with the public interest. The pause in approvals by the DOE could potentially result in a delay in obtaining approvals to export LNG to non-FTA nations for future projects.

F-42

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Venture Global, Inc.

We have audited the consolidated financial statements of Venture Global, Inc. (the Company) as of December 31, 2023 and 2022, for each of the three years in the period ended December 31, 2023, and have issued our report thereon dated February 22, 2024 included elsewhere in this Form S-1. Our audits of the consolidated financial statements included the financial information included in the financial statement schedule listed in Item 16(b) of this Form S-1 (the “schedule”). This schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s schedule, based on our audits.

In our opinion, the schedule presents fairly, in all material respects, the information set forth therein when considered in conjunction with the consolidated financial statements.

/s/ Ernst & Young LLP

Tysons, VA

February 28, 2024

F-43

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

BALANCE SHEETS

($ in millions)


	December 31,
	2023		2022
ASSETS
Current assets
Cash	$	—	$	—
Accounts receivable from subsidiary		—		1

Total current assets		—		1

Property, plant and equipment, net		3		—
Right-of-use assets		3		3
Investment in subsidiaries, net		1,512		36

TOTAL ASSETS	$	1,518	$	40

LIABILITIES AND EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	2	$	—
Accrued and other liabilities		—		6
Accounts payable to subsidiary		3		11

Total current liabilities		5		17

Long-term debt, net		—		206
Operating lease liabilities		3		3

Total liabilities		8		226

Equity
Stockholders’ and members’ equity (deficit)		1,510		(186	)

TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	1,518	$	40

See the accompanying notes to Schedule I.

F-44

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF OPERATIONS

($ in millions)


	Years ended December 31,
	2023			2022			2021
MANAGEMENT FEE FROM SUBSIDIARIES	$	5		$	6		$	6

OPERATING EXPENSE
General and administrative expense		2			2			1

Total operating expense		2			2			1

INCOME FROM OPERATIONS		3			4			5
OTHER EXPENSE
Interest expense, net		(29	)		(28	)		(7	)

Total other expense		(29	)		(28	)		(7	)

LOSS BEFORE INCOME TAXES AND EQUITY INCOME (LOSS) OF SUBSIDIARIES		(26	)		(24	)		(2	)
Less: income tax expense		—			—			—
Add: equity in income (loss) of subsidiaries, net of income taxes		2,707			1,882			(354	)

NET INCOME (LOSS)	$	2,681		$	1,858		$	(356	)

See the accompanying notes to Schedule I.

F-45

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF CASH FLOWS

($ in millions)


	Years ended December 31,
	2023			2022			2021
OPERATING ACTIVITIES	$	6		$	5		$	7
INVESTING ACTIVITIES
Purchases of property, plant and equipment		(1	)		—			—

Net cash used by investing activities		(1	)		—			—

FINANCING ACTIVITIES
Proceeds from issuance of debt		115			—			189
Distributions from subsidiaries		71			—			—
Purchase of subsidiary interests		—			—			(185	)
Payments of financing and issuance costs		(42	)		—			(4	)
Distributions to members		(149	)		(6	)		(7	)

Net cash used by financing activities		(5	)		(6	)		(7	)

Net decrease in cash		—			(1	)		—
Cash at beginning of period		—			1			1

CASH AT END OF PERIOD	$	—		$	—		$	1

See the accompanying notes to Schedule I.

F-46

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONDENSED FINANCIAL INFORMATION OF PARENT

Note 1 – Basis of presentation

The Condensed Financial Statements represent the financial information required by the Securities and Exchange Commission Regulation S-X 5-04 for Venture Global, Inc. (“Venture Global” or “the Parent Company”). Venture Global was formed by the managing members of Venture Global Partners II, LLC (“VG Partners”) on September 19, 2023 under the name of Venture Global Holdings, Inc. In January 2024, the Parent Company changed its name from Venture Global Holdings, Inc. to Venture Global, Inc.

In September 2023, Venture Global was party to certain reorganization transactions (the “Reorganization Transactions”) whereby Venture Global Partners, LLC (“Legacy VG Partners”), a then wholly-owned subsidiary of VG Partners and the controlling shareholder of Venture Global LNG, Inc. (“VGLNG”), merged with and into Venture Global (the “2023 Merger”), with VG Partners receiving 435,500 shares of Venture Global’s Class A common stock in exchange for 100% of its equity interests in Legacy VG Partners. In connection with the Reorganization Transactions, the non-controlling VGLNG shareholders, holding 84,272 shares of VGLNG’s issued and outstanding Series C common stock, received 84,272 shares of Class A common stock of Venture Global, in a one-for-one exchange for their shares of VGLNG (the “NCI Acquisition”). All shares of Series A, Series B and Series C common stock of VGLNG were retired upon completion of the Reorganization Transactions in September 2023. No cash was exchanged as part of the Reorganization Transactions and Venture Global incurred $40 million of third-party transaction costs in connection with its formation and the issuance of its shares of Class A common stock.

The 2023 Merger was accounted for as a transaction between entities under common control. Prior to the 2023 Merger, Venture Global, as a standalone entity, had no operations and had no assets or liabilities. The financial results and other information included in the Condensed Financial Statements for periods prior to the Reorganization Transactions were applied on a retrospective basis and are reflective of VG Partners.

In the Condensed Financial Statements, the Parent Company’s investment in subsidiaries are presented at the net amount attributable to Venture Global under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are reflected on the Condensed Balance Sheets. The net income or loss from operations of the subsidiaries is reported in equity or loss in income of subsidiaries, excluding income or loss from non-controlling interests.

A substantial amount of Venture Global’s operating, investing and financing activities are conducted by its affiliates. The Condensed Financial Statements should be read in conjunction with Venture Global’s Consolidated Financial Statements.

Note 2 – Investment in Subsidiaries

In December 2022, VGLNG, the Parent Company’s partially owned subsidiary, repurchased 55,000 Series B and 23,700 Series C shares of its common stock for $1.4 billion. VGLNG’s repurchase of its outstanding common stock increased Venture Global’s controlling interest in the subsidiary to 71.8% and was accounted for as an equity transaction. To reflect this change in ownership interest, the Parent Company recognized a $923 million decrease to Investment in subsidiaries for the year ended December 31, 2022.

In addition, during the year ended December 31, 2023, prior to the Reorganization Transactions, VGLNG repurchased 5,000 shares of its Series B common stock and 81,896 shares of its Series C common stock for $1.6 billion. VGLNG’s repurchase of its outstanding common stock increased Venture Global’s controlling interest in the subsidiary to 83.8% and was accounted for as an equity transaction. To reflect this change in ownership interest, the Parent Company recognized a $1.1 billion decrease to Investment in subsidiaries for the year ended December 31, 2023.

F-47

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

VENTURE GLOBAL, INC.

NOTES TO THE CONDENSED FINANCIAL INFORMATION OF PARENT

After the Reorganization Transactions, Venture Global owned 100% of VGLNG. See Note 1 – Basis of presentation for further discussion.

Note 3 – Debt

The following table summarizes the Parent Company’s outstanding debt (in millions):


	December 31,
	2023		2022
Fixed rate:
VGC 2024 Term Loan	$	—	$	205

Total outstanding debt		—		205

Plus: unamortized debt discount and issuance costs		—		1

Total outstanding debt, net		—		206
Less: current portion of long-term debt		—		—

Total long-term debt, net	$	—	$	206

VGC 2024 Term Loan

In August 2021, Legacy VG Partners and Venture Global Commodities, LLC (“VGC”), as co-borrowers, entered into a senior secured term loan facility due August 2024 (the “VGC 2024 Term Loan”). During the year ended December 31, 2023, the Parent Company increased the borrowing under the VGC 2024 Term Loan by an additional $115 million, and transferred the full outstanding VGC 2024 Term Loan balance to VGC, its wholly-owned subsidiary, which resulted in a non-cash distribution to the Parent Company of $339 million.

Note 4 – Supplemental Cash Flow Information

The following table sets forth supplemental disclosure of cash flow information (in millions):


	Years ended December 31,
	2023		2022		2021
Venture Global share-based compensation incurred by subsidiary	$	141	$	—		—
Paid-in-kind interest on VGC 2024 Term loan		19		13		3
Accrued purchases of property, plant and equipment		2		—		—
Cash paid for interest		—		7		1
Right-of-use assets in exchange for new operating lease liabilities		—		3		—

F-48

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

Shares

Class A common stock

Venture Global, Inc.

LOGO

PROSPECTUS

, 2024

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution


	Amount to Be Paid
SEC registration fee	$	*
FINRA filing fee		*
Listing fee		*
Transfer agent’s fees		*
Printing and engraving expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Blue Sky fees and expenses		*
Miscellaneous		*

Total	$	*

*	To be completed by amendment.

Each of the amounts set forth above, other than the registration fee and the FINRA filing fee, is an estimate.

Item 14. Indemnification of Directors and Officers

Section 145 of the Delaware General Corporation Law provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with any threatened, pending or completed actions, suits or proceedings in which such person is made a party by reason of such person being or having been a director, officer, employee or agent to the registrant. The Delaware General Corporation Law provides that Section 145 is not exclusive of other rights to which those seeking indemnification may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise. Upon completion of this offering, the registrant’s amended and restated certificate of incorporation and amended and restated bylaws will provide for indemnification by the registrant of its directors, officers and employees to the fullest extent permitted by the Delaware General Corporation Law. Upon completion of this offering, the registrant will enter into indemnification agreements with each of its current directors and officers to provide these directors and executive officers additional contractual assurances regarding the scope of the indemnification set forth in the registrant’s amended and restated certificate of incorporation and amended and restated bylaws and to provide additional procedural protections. There is no pending litigation or proceeding involving a director or executive officer of the registrant for which indemnification is sought.

Section 102(b)(7) of the Delaware General Corporation Law permits a corporation to provide in its certificate of incorporation that a director or officer of the corporation shall not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director or officer, except for liability (i) for any breach of the director’s or officer’s duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for a director for unlawful payments of dividends or unlawful stock repurchases, redemptions or other distributions, (iv) for any transaction from which the director or officer derived an improper personal benefit or (v) for an officer in any action by or in the right of the corporation. The registrant’s amended and restated certificate of incorporation will provide for such limitation of liability.

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

The registrant maintains standard policies of insurance under which coverage is provided (a) to its directors and officers against loss rising from claims made by reason of breach of duty or other wrongful act, and (b) to the registrant with respect to payments which may be made by the registrant to such officers and directors pursuant to the above indemnification provision or otherwise as a matter of law.

The proposed form of underwriting agreement filed as Exhibit 1 to this registration statement provides for indemnification of directors and officers of the registrant by the underwriters against certain liabilities.

Item 15. Recent Sales of Unregistered Securities

For the past three fiscal years, the registrant has issued and sold the following securities without registration under the Securities Act:

(a) Issuances of Common Stock

In connection with the Reorganization Transactions, the Company issued (i) 78,464 shares of Class A common stock to certain entities affiliated with Pacific Investment Management Company then holding VGLNG’s Series C common stock, (ii) 435,500 shares of Class A common stock to VG Partners, in exchange for its equity interests in Venture Global Partners, LLC and (iii) 5,808 shares of Class A common stock to certain other holders of VGLNG’s Series C common stock, in exchange for such VGLNG’s Series C common stock.

In connection with the common stock issuances described above, we relied on the exemption from registration provided by Section 4(a)(2) of the Securities Act on the basis that the transactions did not involve a public offering.

In connection with this offering, all of the outstanding shares of Class A common stock held by VG Partners will convert into an aggregate of shares of Class B common stock, par value $0.01 per share. The automatic conversion of such shares will not represent an offer or sale of securities under the Securities Act.

(b) Grants of Options

Prior to the Reorganization Transactions, VGLNG granted stock options to purchase shares of its Series A common stock pursuant to VGLNG’s 2014 Stock Option Plan (as amended from time to time), or the 2014 Plan, since the 2014 Plan’s adoption on December 16, 2014. In connection with the Reorganization Transactions, all such options outstanding under the 2014 Plan were automatically converted, on a one-for-one basis, in accordance with and pursuant to the terms of the 2014 Plan, into options to purchase shares of our Class A common stock, subject to the terms and conditions of our 2023 Stock Option Plan, or the 2023 Plan. Such option grants were as follows (without giving effect to the -for-1 stock split on Class A common stock to be effected in connection with this offering):

•

between March 8, 2021 and June 23, 2021, VGLNG granted options to purchase an aggregate of 4,050 shares of its Series A common stock, with an exercise price per share of $7,000, to certain of its current executive officers and other employees;

•

between August 9, 2021 and October 29, 2021, VGLNG granted options to purchase an aggregate of 1,650 shares of its Series A common stock, with an exercise price per share of $10,000, to certain of its current directors and other employees;

•

between January 14, 2022, and January 28, 2022, VGLNG granted options to purchase an aggregate of 1,000 shares of its Series A common stock, with an exercise price per share of $12,000, to certain of its current directors;

•

between May 12, 2022, and September 6, 2022, VGLNG granted options to purchase an aggregate of 8,000 shares of its Series A common stock, with an exercise price per share of $15,300, to certain of its current executive officers and other employees;

II-2

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

•

between February 6, 2023, and June 1, 2023, VGLNG granted options to purchase an aggregate of 600 shares of its Series A common stock, with an exercise price per share of $18,000, to certain of its current directors and other employees;

•

on July 17, 2023, VGLNG granted options to purchase an aggregate of 100 shares of its Series A common stock, with an exercise price per share of $23,700, to certain of its current employees; and

•

on February 22, 2024, VGLNG granted options to purchase an aggregate of 100 shares of its Series A common stock, with an exercise price per share of $29,200 to certain of its current employees.

For all of the option grants described above, we relied on the exemption from registration provided by Rule 701 under the Securities Act on the basis that the 2014 Plan and the 2023 Plan are each a written compensatory benefit plan and at the time of the grants we were not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act and were not an investment company registered or required to be registered under the Investment Company Act of 1940, as amended.

All of the foregoing securities are deemed restricted securities for purposes of the Securities Act. All certificates representing the issued shares of capital stock described in this Item 15 included appropriate legends setting forth that the securities have not been registered and the applicable restrictions on transfer.

Item 16. Exhibits and Financial Statement Schedules

(a)

Exhibits: The list of exhibits set forth under “Exhibit Index” at the end of this Registration Statement is incorporated herein by reference.

(b)

Financial Statement Schedules. Schedule I – Condensed Financial Information of Venture Global, Inc. is included in the Registration Statement beginning on page F-43.

Item 17. Undertakings

The undersigned registrant hereby undertakes:

(a)

The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

(b)

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions referenced in Item 14 of this registration statement, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(c)

The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

(2)

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-4

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

EXHIBIT INDEX


Exhibit Number		Description

1.1*		Form of Underwriting Agreement

3.1*		Form of Second Amended and Restated Certificate of Incorporation (to be effective upon consummation of this offering)

3.2*		Form of Third Amended and Restated By-Laws (to be effective upon consummation of this offering)

4.1*		Form of Class A Common Stock Certificate

5.1*		Opinion of Davis Polk & Wardwell LLP

10.1*		Form of Amended and Restated Shareholders’ Agreement (to be effective upon consummation of this offering)

10.2§†		Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.3§†		Guaranty Agreement, dated as of April 21, 2021, by KBR, Inc., for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 21, 2021, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.4§†		Guaranty Agreement, dated as of April 21, 2021, by Zachry Holdings, Inc., for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 21, 2021, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.5§†		Limited Notice to Proceed No.1 (ITP), dated as of September 24, 2021, pursuant to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 21, 2021, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.6§†		Change Order No. 1, dated as of May 17, 2022, to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.7§†		Change Order No. 2, dated as of May 20, 2022, to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.8§†		Change Order No. 3, dated as of September 30, 2022, to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.9§†		Amendment No. 1 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of October 11, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.10§†		Change Order No. 4, dated as of October 12, 2022, to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.11§†		Amendment No. 2 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of February 1, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.12§†		Change Order No. 5, dated as of March 2, 2023, to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 7, 2022, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.13§†		Amendment No. 3 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of September 26, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.14§†		Amendment No. 4 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of September 26, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.15§†		Amendment No. 5 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of January 19, 2024, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.16§†		Amendment No. 6 to the Second Amended and Restated Engineering, Procurement and Construction Agreement, dated as of July 2, 2024, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.17§†		Engineering, Procurement and Construction Agreement, dated as of January 10, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.18§†		Guaranty Agreement, dated as of January 10, 2023, by KBR Inc., for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Engineering, Procurement and Construction Agreement, dated as of January 10, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.19§†		Guaranty Agreement, dated as of January 10, 2023, by Zachry Holdings, Inc., for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Engineering, Procurement and Construction Agreement, dated as of January 10, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.20§†		Amendment No. 1 to the Engineering Procurement and Construction Agreement, dated as of September 26, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.21§†		Amendment No. 2 to the Engineering, Procurement and Construction Agreement, dated as of July 2, 2024, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.22§†		Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.23§†		Guaranty Agreement, dated as of June 8, 2023, by Worley Limited, for the benefit of Venture Global CP2 LNG, LLC, pursuant to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.24§†		Change Order No. 1, dated as of November 9, 2023, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.25§†		Change Order No. 2, dated as of November 30, 2023, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

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CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.26§†		Change Order No. 3, dated as of February 23, 2024, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.27§†		Change Order No. 4, dated as of March 14, 2024, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.28§†		Change Order No. 5, dated as of April 1, 2024, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.29§†		Amendment No. 1 to the Engineering, Procurement and Construction Agreement, dated as of May 10, 2024, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.30§†		Amendment No. 2 to the Engineering, Procurement and Construction Agreement, dated as of May 22, 2024, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.31§†		Change Order No. 6 Rev. 1, dated as of June 17, 2024, to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc.

10.32§		Fourth Amended and Restated Letter of Agreement, dated as of April 7, 2023, by and between Venture Global LNG, Inc. and Baker Hughes Energy Services LLC

10.33§		Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.34§		Guaranty Agreement, dated as of February 26, 2021, by Baker Hughes Holdings LLC, for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of February 26, 2021, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.35§		Change Order No. 2, dated as of February 25, 2022, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.36§		Change Order No. 3, dated as of October 24, 2022, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.37§		Change Order No. 4, dated as of April 7, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.38§		Change Order No. 5, dated as of May 18, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.39§		Change Order No. 6, dated as of December 29, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.40§		Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

II-7

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.41§		Guaranty Agreement, dated as of August 5, 2022, by Baker Hughes Holdings LLC, for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.42§		Change Order No. 1, dated as of April 7, 2023, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.43§		Change Order No. 2, dated as of May 24, 2023, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.44§		Change Order No. 3, dated as of August 29, 2024, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.45§		Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC

10.46§		Change Order No. 1, dated as of August 8, 2024, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC

10.47§		Guaranty Agreement, dated as of April 13, 2023, by Baker Hughes Holdings LLC, for the benefit of Venture Global CP2 LNG, LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC

10.48§		Guaranty Agreement, dated as of May 4, 2023, by Venture Global LNG, Inc., for the benefit of Baker Hughes Energy Services LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC

10.49*		Amended and Restated Ground Lease Agreement, dated as of July 15, 2019, by and between Venture Global Calcasieu Pass, LLC and JADP Venture, LLC

10.50*		First Amendment to Amended and Restated Ground Lease Agreement, dated as of December 12, 2023, by and between Venture Global Calcasieu Pass, LLC and JADP Venture, LLC

10.51*		Amended and Restated Ground Lease Agreement, dated as of June 20, 2019, by and between Venture Global Calcasieu Pass, LLC and Henry Venture LLC

10.52*		Ground Lease Agreement, dated as of July 19, 2021, by and between Venture Global Plaquemines LNG, LLC and the Plaquemines Port Harbor and Terminal District

10.53*		Ground Lease Agreement, dated as of January 19, 2022, by and between Plaquemines Land Ventures, LLC, and the Plaquemines Port Harbor and Terminal District

10.54*		Amended and Restated Ground Lease Agreement, dated as of September 19, 2023, by and between Cameron Land Ventures, LLC and J.A. Davis Properties, LLC

10.55*		Ground Lease Agreement, dated of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Wilma Davis Bride Family, LLC

10.56*		Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Ardoin Henry, LLC

10.57*		Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC and Miller Estate Leasing Company, LLC

II-8

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.58*		Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Charlotte Ann LaBove and Carlotta Ann Savoie

10.59*		Ground Lease Agreement, dated as of October 24, 2023, by and between Venture Global CP2 LNG, LLC and Cameron Parish Port, Harbor and Terminal District

10.60*		Ground Lease Agreement, dated as of March 11, 2019, by and between Venture Global Calcasieu Pass, LLC and Henry Venture, LLC

10.61*		Ground Lease Agreement, dated as of December 12, 2023, by and between Venture Global CP2 LNG, LLC and JADP Venture, LLC

10.62§		Limited Liability Company Agreement, dated as of August 19, 2019, among Calcasieu Pass Funding, LLC and the Members named therein

10.63§		Limited Liability Company Agreement, dated as of August 19, 2019, by and among Calcasieu Pass Holdings, LLC and the Members named therein

10.64§		Amendment No. 1 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of February 8, 2021

10.65§		Amendment No. 1 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of February 8, 2021

10.66§		Amendment No. 2 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of October 27, 2021

10.67§		Amendment No. 2 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of October 27, 2021

10.68§		Amendment No. 3 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of July 30, 2022

10.69§		Amendment No. 3 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of July 30, 2022

10.70*		Credit Facility Agreement, dated as of August 19, 2019, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline, LLC, the lenders party thereto from time to time, the issuing banks thereto from time to time, Natixis, New York Branch, as credit facility agent, and Mizuho Bank (USA), as collateral agent

10.71*		Common Terms Agreement for the Loans, dated as of August 19, 2019, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline, LLC, Natixis, New York Branch, as credit facility agent, Mizuho Bank, Ltd., as intercreditor agent, and each other facility agent party thereto from time to time

10.72*		Consent and Amendment to the Common Terms Agreement and the Credit Facility Agreement, dated as of December 28, 2020, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019

10.73*		Second Amendment to the Common Terms Agreement and Consent to the Credit Facility Agreement, dated as of January 26, 2021, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019

10.74*		Consent and Amendment to Credit Facility Agreement, dated as of September 30, 2021, in respect of the Credit Facility Agreement, dated as of August 19, 2019

II-9

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.75*		Third Amendment to the Common Terms Agreement, First Amendment to the Common Security and Account Agreement and Consent to the Credit Facility Agreement, dated May 25, 2022, in respect of the Common Terms Agreement, dated as of August 19, 2019, the Common Security and Account Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019

10.76*		Fourth Amendment to the Common Terms Agreement and Second Amendment to the Credit Facility Agreement, dated as of October 12, 2022, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019

10.77*		Fifth Amendment to the Common Terms Agreement and Third Amendment to the Common Security and Account Agreement, dated as of February 27, 2023, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Common Security and Account Agreement, dated as of August 19, 2019

10.78*		Third Amendment to the Credit Facility Agreement, dated as of May 26, 2023, in respect of the Credit Facility Agreement, dated as of August 19, 2019

10.79*		Sixth Amendment to the Common Terms Agreement and Fourth Amendment to the Common Security and Account Agreement, dated as of June 30, 2023, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Common Security and Account Agreement, dated as of August 19, 2019

10.80*		Indenture, dated as of August 5, 2021, by and among Venture Global Calcasieu Pass, LLC, as Issuer, TransCameron Pipeline LLC, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the Issuer’s 3.875% Senior Secured Notes due 2029 and 4.125% Senior Secured Notes due 2031

10.81*		First Supplemental Indenture, dated as of November 22, 2021, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of August 5, 2021

10.82*		Second Supplemental Indenture, dated as of January 13, 2023, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of August 5, 2021

10.83*		Amended and Restated Credit Facility Agreement, dated as of March 13, 2023, by and among Venture Global Plaquemines LNG, LLC, Venture Global Gator Express, LLC, the lenders party thereto from time to time, the issuing banks thereto from time to time, Natixis, New York Branch, as credit facility agent, and Royal Bank of Canada, as collateral agent

10.84*		Amended and Restated Common Terms Agreement for the Loans, dated as of March 13, 2023, by and among Venture Global Plaquemines LNG, LLC, Venture Global Gator Express, LLC, Natixis, New York Branch, as credit facility agent, and Royal Bank of Canada, as intercreditor agent

10.85*		Amendment No. 1 to the Common Terms Agreement, dated as of September 29, 2023, in respect of the Amended and Restated Common Terms Agreement, dated as of March 13, 2023

10.86*		Amendment No. 2 to the Common Terms Agreement, dated as of May 15, 2024, in respect of the Amended and Restated Common Terms Agreement and Amendment No. 1 to the Common Security and Account Agreement, dated as of March 13, 2023

10.87*		Indenture, dated as of May 26, 2023, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 8.125% Senior Secured Notes due 2028 and 8.375% Senior Secured Notes due 2031

II-10

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.88*		First Supplemental Indenture, dated as of September 25, 2023, by and between Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of May 26, 2023

10.89*		Second Supplemental Indenture, dated as of September 28, 2023, by and among Venture Global Commodities, LLC, Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of May 26, 2023

10.90*		Third Supplemental Indenture, dated as of October 24, 2023, by and among Venture Global Commodities, LLC, Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture, dated as of May 26, 2023

10.91*		Indenture, dated as of October 24, 2023, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 9.500% Senior Secured Notes due 2029 and 9.875% Senior Secured Notes due 2032

10.92*		First Supplemental Indenture, dated as of November 8, 2023, by and between Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of October 24, 2023

10.93*		Indenture, dated as of July 24, 2024, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 7.00% Senior Secured Notes due 2030

10.94*		Management Services Agreement, dated as of December 1, 2014, by and between Venture Global Commodities, LLC and Venture Global Partners, LLC

10.95*		Second Amended and Restated Management Services Agreement, dated as of April 20, 2015, by and between Venture Global LNG, Inc. and Venture Global Partners, LLC

10.96*#		Venture Global Holdings, Inc. 2023 Stock Option Plan

10.97*#		Form of Venture Global Holdings, Inc. 2023 Stock Option Plan Non-Qualified Stock Option Agreement

10.98*#		Venture Global, Inc. Omnibus Incentive Plan

10.99*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Michael Sabel, dated as of

10.100*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Jonathan Thayer, dated as of

10.101*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Robert Pender, dated as of

10.102*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Thomas Earl, dated as of

10.103*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Keith Larson, dated as of

10.104*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Brian Cothran, dated as of

10.105*#		Executive Employment Agreement, by and between Venture Global LNG, Inc. and Fory Musser, dated as of

10.106*#		Form of Restrictive Covenant Agreement

II-11

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83


Exhibit Number		Description

10.107*#		Form of Indemnification Agreement

21.1*		Subsidiaries of the registrant

23.1*		Consent of Independent Registered Public Accounting Firm

23.2*		Consent of Davis Polk & Wardwell LLP (included in Exhibit 5.1)

24.1*		Power of Attorney (included on signature page)

107*		Filing Fee Exhibit

*	To be filed by amendment.

†	Previously filed.

#	Indicates management contract or compensatory plan.

§	Portions of this exhibit have been omitted in compliance with Regulation S-K, Item 601(a)(6) and/or Item 601(b)(10)(iv).

II-12

CONFIDENTIAL TREATMENT REQUESTED PURSUANT TO RULE 83

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Arlington, Virginia, on the day of , 2024.


VENTURE GLOBAL, INC.

By:
		Name:Michael Sabel
		Title: Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Michael Sabel and Keith Larson, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any and all additional registration statements pursuant to Rule 462(b) of the Securities Act of 1933, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agents full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.


Signature	Title	Date

Michael Sabel	Chief Executive Officer, Director, Executive Co-Chairman of the Board, and Founder	, 2024

Robert Pender	Executive Co-Chairman, Director, Executive Co-Chairman of the Board, and Founder	, 2024

Jonathan Thayer	Chief Financial Officer	, 2024

Sari Granat	Director	, 2024

Andrew Orekar	Director	, 2024

Thomas J. Reid	Director	, 2024

Jimmy Staton	Director	, 2024

Roderick Christie	Director	, 2024

II-13