Edgar Filing: CHENIERE ENERGY INC

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Filed Pursuant to Rule 424(b)(5)
Registration No. 333-111454

Prospectus Supplement
(To Prospectus dated September 10, 2004)

5,000,000 shares

Common stock

Cheniere Energy, Inc. is selling all of the shares of common stock in this offering.

Our common stock is listed on the American Stock Exchange under the symbol "LNG." On December 2, 2004, the closing price of our common stock on that exchange was $61.85 per share.

	Per share		Total


Initial public offering price	$	60.00	$	300,000,000.00
Underwriting discounts	$	2.70	$	13,500,000.00
Proceeds to Cheniere, before expenses	$	57.30	$	286,500,000.00

We have granted the underwriters an option for a period of 30 days to purchase up to 750,000 additional shares of common stock on the same terms and conditions set forth above to cover over-allotments, if any.

Investing in our common stock involves a high degree of risk. See "Risk factors" beginning on page S-9 of this prospectus supplement and on page 6 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus supplement or the accompanying prospectus. Any representation to the contrary is a criminal offense.

J.P. Morgan Securities Inc. will act as sole book-running manager and, on behalf of the underwriters, expects to deliver the shares on or about December 8, 2004.

JPMorgan
Merrill Lynch & Co.		Petrie Parkman & Co.
Pritchard Capital Partners LLC

December 2, 2004

Table of Contents

Prospectus Supplement

Executive summary

The offering

Risk factors

Forward-looking statements

Use of proceeds

Dividend policy

Price range of common stock

Capitalization

Summary selected consolidated financial data

Management's discussion and analysis of financial condition and results of operations

Business

Management

Principal stockholders

Certain relationships and transactions

Underwriting

Legal matters

Experts

Interests of named experts and counsel

Glossary of energy terms

Where you can find more information

Prospectus

About this prospectus

Where you can find more information

Cautionary statement regarding forward-looking statements

Cheniere Energy, Inc.

Risk factors

Use of proceeds

Ratios of earnings to fixed charges

Description of capital stock

Description of debt securities

Description of warrants

Interests of named experts and counsel

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of shares of our common stock. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this offering. If the information about the offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

No action is being taken in any jurisdiction outside the United States to permit a public offering of common stock or possession or distribution of this prospectus supplement and the accompanying prospectus in that jurisdiction. Persons who come into possession of this prospectus supplement or the accompanying prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restriction as to this offering and the distribution of this prospectus supplement and the accompanying prospectus applicable to those jurisdictions.

Executive summary

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. Because this is only a summary, it does not contain all the information that may be important to you. You should read the entire prospectus supplement, the accompanying prospectus and the documents incorporated by reference carefully, especially "Risk factors" beginning on page S-9 of this prospectus supplement and page 6 of the accompanying prospectus, before deciding to invest in our common stock. Unless otherwise indicated, all information contained in this prospectus supplement assumes the underwriters' over-allotment option will not be exercised. As used in this prospectus supplement and the accompanying prospectus, unless we indicate otherwise, the terms "our," "we," "us" and similar terms refer to Cheniere Energy, Inc., our subsidiaries and certain other entities in which we own an interest.

Overview

Cheniere Energy, Inc. is an independent energy company engaged primarily in developing, constructing, owning and operating onshore liquefied natural gas, or LNG, receiving terminals along the Gulf Coast of the United States. LNG is natural gas that, through a refrigeration process, has been reduced to a liquid state, which represents approximately 1/600^th of its gaseous volume. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. LNG is transported using large oceangoing tankers specifically constructed for this purpose. LNG receiving terminals offload LNG from tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market. We generally provide regasification services under long-term contracts referred to in the industry as terminal use agreements, or TUAs.

We believe that our planned LNG projects are well-positioned as compared to other proposed projects based on a number of competitive strengths. We have secured what we believe to be among the best sites for LNG receiving terminals along the U.S. Gulf Coast, an area that is highly conducive to such development given the substantial local consumption, existing industrial complexes and access to significant natural gas pipeline infrastructure. Furthermore, we believe that our terminals are further along in the development process than most other proposed U.S. terminals, with three of our terminals currently expected to commence construction in 2005. We have entered into long-term TUAs with well-known "anchor tenants" for a significant portion of our planned LNG receipt capacity. Our experienced management team has sought to protect our early mover advantage by planning our facilities based on proven technology and design concepts and by employing an environmental and community friendly approach to the development of our projects. This approach and the locations and capacities of our proposed facilities are intended to benefit from economies of scale and mitigate construction delays.

Under our TUAs, customers will typically be required to pay monthly capacity reservation fees, whether or not they use the terminals. Long-term TUAs have already been signed with ConocoPhillips Company and The Dow Chemical Company for the Freeport LNG facility, and with subsidiaries of Total S.A. and ChevronTexaco Corporation for the Sabine Pass LNG facility.

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In addition, we own a minority interest in J & S Cheniere S.A., which charters LNG tankers that transport LNG on the spot market. We are also engaged, to a lesser extent, in oil and natural gas exploration, development and production activities in the Gulf of Mexico.

LNG Industry

LNG is a well-established, global source of natural gas for electric generation, heating and industrial applications. According to the Energy Information Administration, or EIA, as of October 2003, there were 66 liquefaction plants in 12 countries capable of producing 6.6 trillion cubic feet, or Tcf, of LNG per year and 44 receiving terminals in 12 countries capable of receiving and regasifying LNG. The EIA also reports Japan as the largest importer of LNG in 2003, importing approximately 7.7 billion cubic feet per day, or Bcf/d, followed by South Korea (2.5 Bcf/d), Spain (1.4 Bcf/d), and North America (1.4 Bcf/d).

North America has the largest interconnected natural gas market in the world, consuming approximately 74 Bcf/d in 2003, according to the EIA. Currently, there are only four import LNG receiving terminals in North America with a combined sustainable sendout capacity of approximately 2.5 Bcf/d, or about 3% of total current natural gas consumption. By contrast, EIA reports that Japan imports more than 80% of its natural gas as LNG.

LNG's contribution to the North American market has historically been minimal, due mainly to an abundant supply of domestically sourced, low cost natural gas. The EIA has reported, however, that the average wellhead price of natural gas produced in the United States has more than doubled in the last five years, an indication of a declining domestic resource base. Chairman of the Federal Reserve, Alan Greenspan, stated in April 2004 that greater access to global natural gas reserves is required for North American natural gas markets "to be able to adjust effectively to unexpected shortfalls in domestic supply [and that] access to world natural gas supplies will require a major expansion of LNG terminal import capacity." We believe that LNG is needed as a reliable source of supply to meet demand and that LNG can be delivered to North America at a competitive price.

Our LNG Receiving Terminals

We began developing our LNG receiving terminal business in 1999, and we have been among the first companies to secure sites and commence development of new LNG receiving terminals in the United States. We have focused our initial development efforts on three LNG receiving terminal projects, located near Freeport, Texas, in Cameron Parish, Louisiana near Sabine Pass, and near Corpus Christi, Texas. For certain statistical data related to these three proposed facilities, see the table set forth below on page S-3.

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The following table sets forth selected information about our three planned LNG receiving terminal development projects:

Freeport LNG

Sabine Pass LNG

Corpus Christi LNG

Cheniere's current

•

30% limited partner

•

100% limited partner

•

66.7% limited partner

interests

•

100% general partner

•

100% general partner

Designed regasification capacity

1.5 Bcf/d

2.6 Bcf/d

Capacity reservations/options(1)

•

ConocoPhillips
(1.0 Bcf/d)

•

Total LNG USA
(1.0 Bcf/d)

•

BPU LNG
(100 Mmcf/d—option)

•

Dow (500 Mmcf/d)

•

Chevron USA
(500 Mmcf/d to 1.0

•

J&S Cheniere
(200 Mmcf/d—option)

Bcf/d—options)(2)

•

Currently marketing

•

J&S Cheniere
(200 Mmcf/d—option)

balance of capacity

Estimated construction costs (before financing costs)(3)

$650—$750 million

$750—$850 million

$650—$750 million

Designed LNG storage capacity/tanks/ unloading berths

6.7 Bcfe/2 tanks/1 dock

10.1 Bcfe/3 tanks/2 docks

FERC status

Final order received June 2004

Final order expected 4^th quarter 2004; Final Environmental Impact Statement (FEIS) issued November 2004

Final order expected 2^nd quarter 2005; Draft Environmental Impact Statement (DEIS) issued November 2004

Expected groundbreaking

1^st quarter 2005

3^rd quarter 2005

Expected completion of construction

Late 2007

2008

2009

Site acreage

233 acres

568 acres

610 acres

(1): We describe our capacity reservations in Mmcf/d or Bcf/d. These amounts approximate the Mmbtu contractual provisions set forth in each TUA as follows: 390,550,000 Mmbtu per contract year under the ConocoPhilips TUA; 195,275,000 Mmbtu per contract year under the Dow TUA; 390,915,000 Mmbtu per contract year under the Total TUA; and 201,972,750 to 403,945,500 Mmbtu per contract year under the Chevron USA TUA.
(2): The TUA has been executed for 700 Mmcf/d, subject to final corporate approvals, including the approval of ChevronTexaco's board of directors, by December 20, 2004. Chevron USA has the option to reduce its reserved capacity at the facility to 500 Mmcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005.
(3): Estimated construction costs are subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices.

Freeport LNG

We initiated the Freeport LNG project and continue to hold a 30%, non-operating, limited partner interest in Freeport LNG Development, L.P., or Freeport LNG. The Freeport LNG receiving terminal will be located in Freeport, Texas. The Freeport LNG terminal is designed to have approximately 1.5 Bcf/d of regasification capacity.

The Freeport LNG terminal is fully subscribed under TUAs for at least 20 years with ConocoPhillips for 1.0 Bcf/d and with Dow for 500 Mmcf/d. As a limited partner of Freeport LNG, we must rely on the general partner to successfully implement Freeport LNG's business

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plans, and we are generally required to keep economic terms of the Freeport LNG TUAs confidential. ConocoPhillips and Dow will both pay monthly capacity reservation fees regardless of usage and a portion of power, fuel and other operating costs.

ConocoPhillips has also agreed to provide a substantial majority of the construction funding for the Freeport LNG facility. ConocoPhillips also owns a 50% interest in the general partner entity responsible for managing construction and operation. In the event of an expansion of the Freeport LNG facility, ConocoPhillips has options to acquire up to 500 Mmcf/d of additional regasification capacity.

Based on discussions with Freeport LNG, we believe that the cost of constructing the 1.5 Bcf/d Freeport LNG facility will be approximately $650 million to $750 million, before financing costs. We believe that this cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices.

FERC issued an order in June 2004 authorizing Freeport LNG to construct and operate an LNG receiving terminal on the Freeport site, subject to specified conditions that must be satisfied prior to commencement of construction. We expect Freeport LNG to begin construction of its terminal in the first quarter of 2005 and to commence terminal operations in late 2007 at the earliest.

Sabine Pass LNG

We hold 100% of the general partner and limited partner interests in Sabine Pass LNG, L.P. The Sabine Pass LNG receiving terminal will be located in Cameron Parish, Louisiana. The terminal is designed to have approximately 2.6 Bcf/d of regasification capacity.

Sabine Pass LNG has entered into 20-year TUAs with Total and Chevron USA to provide 1.0 Bcf/d and 700 Mmcf/d of regasification capacity, respectively. Each of the TUAs provides for the customer to pay a fee of $0.32 per Mmbtu of reserved capacity regardless of usage, subject in part to adjustment for inflation. The TUA with Chevron USA remains subject to final corporate approvals, including the approval of ChevronTexaco's board of directors, by December 20, 2004. Chevron USA has options either to decrease its reserved capacity to 500 Mmcf/d by July 1, 2005 or to increase its capacity to 1.0 Bcf/d by December 1, 2005.

We estimate that the cost of constructing the 2.6 Bcf/d Sabine Pass LNG facility will be approximately $750 million to $850 million, before financing costs. This estimate is based in part on our ongoing negotiations regarding a lump-sum turnkey contract with a major international engineering, procurement and construction, or EPC, contractor. Our cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices (particularly steel).

HSBC Securities (USA) Inc., or HSBC, and Société Générale have entered into agreements with us to arrange $741 million of non-recourse project debt financing, which we plan to use to fund a substantial majority of the Sabine Pass LNG terminal construction costs. The commitments of HSBC and Société Générale are subject to significant conditions, including due diligence, documentation, syndication, execution of a lump-sum turnkey EPC contract, execution of one or more TUAs for at least 1.0 Bcf/d of long-term capacity commitments and funding of adequate equity contributions to Sabine Pass LNG. We anticipate that the EPC contract we are currently negotiating and the TUA we have already finalized with Total will be

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acceptable to the lenders. We will fund the equity contribution required by the lenders with proceeds from this offering or, if applicable, with proceeds from equity invested in Sabine Pass LNG by Chevron USA or other parties. Chevron USA is currently negotiating with us about making a $200 million equity contribution for a 20% limited partner interest in Sabine Pass LNG. The results of such negotiations should be known by December 20, 2004, but there can be no assurance that any agreement can be reached.

FERC has issued the FEIS for our Sabine Pass facility, concluding that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We anticipate that, by the end of 2004, FERC will issue an order authorizing construction of the Sabine Pass facility, subject to specified conditions that must be satisfied prior to commencement of construction. We expect to begin construction in the first quarter of 2005 and to commence terminal operations in 2008.

Corpus Christi LNG

We hold 100% of the general partner interest and 66.7% of the limited partner interest in Corpus Christi LNG, L.P. The Corpus Christi LNG receiving terminal will be located near Corpus Christi, Texas. The terminal is designed to have approximately 2.6 Bcf/d of regasification capacity. Implementing the strategy that we used for Sabine Pass, we have provided detailed information to, and engaged in preliminary discussions with, potential customers in an effort to secure long-term TUAs for our Corpus Christi terminal. As of this date, Corpus Christi LNG has not entered into any TUAs.

We estimate that the cost of constructing the 2.6 Bcf/d Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs. This estimate is based in part on our negotiations regarding a lump-sum turnkey contract with a major international EPC contractor. Our cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices (particularly steel). We currently plan to obtain funding for the facility using a financing structure similar to the financing strategy that we are using for the Sabine Pass LNG facility.

FERC has issued the DEIS for our Corpus Christi facility, preliminarily concluding that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We anticipate that, by the second quarter of 2005, FERC will issue an order authorizing construction of the Corpus Christi facility, subject to specified conditions that must be satisfied prior to commencement of construction. We expect to begin construction in the third quarter of 2005 and to commence terminal operations in 2009.

Additional Sites

We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG receiving terminals. In November 2004, we announced the acquisition of an option on a proposed LNG site at the mouth of the Calcasieu Channel in Cameron Parish, Louisiana, which we refer to as Creole Trail LNG. We plan to develop Creole Trail in the same manner as our Sabine Pass LNG facility with two docks, three 160,000 cm storage tanks and an initial regasification capacity of 2.6 Bcf/d. We plan to begin the National Environmental Policy Act pre-filing process with FERC in January 2005 and expect the permitting process to take 12 to 18 months.

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Business Strategy and Competitive Strengths

Our goal is to continue to increase shareholder value by pursuing a strategy with the following primary components:

•: complete the development and construction of our onshore U.S. Gulf Coast LNG receiving terminals;
•: secure "anchor tenants" under long-term TUAs for approximately two-thirds of existing and future regasification capacity at the LNG terminals that we control, and retain the remaining capacity for our own account to capitalize on future long-term, short-term or spot market opportunities;
•: apply proven, conventional technology to mitigate development and operating risk and facilitate permitting, while utilizing the latest control and safety technology;
•: grow our terminal business by expanding our existing projects and pursue the development of additional LNG receiving terminals on the U.S. Gulf Coast and elsewhere; and
•: evaluate the use of our receiving terminal assets to pursue upstream opportunities, such as investing in LNG shipping businesses or development of natural gas reserves that could be converted into LNG, as well as downstream opportunities, such as investing in natural gas pipelines and storage.

We believe that we hold several competitive advantages, which drive this strategy and enhance our efforts to increase shareholder value:

Early Mover Advantage. We established our business plan in 1999, when constructing new LNG import capacity in the United States was only beginning to undergo reconsideration since completion of the last domestic LNG import terminal in the early 1970s. As an early mover, we secured what we believe to be among the best sites for LNG receiving terminals along the U.S. Gulf Coast. Today, we believe we have maintained that advantage and believe that our LNG receiving terminals are currently further along in the development process than most other proposed U.S. LNG receiving terminals, with three of our facilities currently expected to commence construction in 2005.

U.S. Gulf Coast Focus. The U.S. Gulf Coast area is conducive to LNG receiving terminal development, as it is distinguished by substantial local consumption coupled with extensive natural gas pipeline infrastructure. According to the EIA natural gas consumption in Texas and Louisiana in 2003 totalled approximately 12.7 Bcf/d and pipeine capacity from the U.S. Gulf Coast in 2001 totalled approximately 19 Bcf/d. Capacity is currently available on major natural gas pipelines in the vicinity of each of our sites and, with declining U.S. Gulf Coast natural gas production, we believe that more of the existing pipeline infrastructure will become available for transporting natural gas imported as LNG.

Economies of Scale and Flexibility. At 2.6 Bcf/d of regasification capacity each, we believe that our Sabine Pass and Corpus Christi facilities are the largest proposed LNG receiving terminals in North America and are each designed to have more than two times the capacity of any existing North American terminal. With this capacity, we believe that these terminals will benefit from economies of scale in construction and operation. Furthermore, with two ports,

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four unloading docks and six storage tanks between the two facilities, we will be capable of offering flexible landing options.

Environmental and Community Friendly Approach. We are committed to an environmentally sound and community friendly approach in developing our LNG receiving terminals. At each potential site, we invest time to develop strong community relationships. We begin the application process for a facility only after we are convinced that the local community understands the process and is willing to support our project. Furthermore, the local governments in Texas and Louisiana are familiar with and supportive of the energy industry. We have received letters in support of the development of our Sabine Pass LNG receiving terminal from Louisiana state representatives, a U.S. Senator from Louisiana, the Governor of Louisiana and local organizations. We have received letters in support of the development of our Corpus Christi LNG receiving terminal from the Governor of Texas, the Mayor of Corpus Christi, the Sierra Club and local organizations. In addition, FERC has held public hearings with respect to the development of our proposed Sabine Pass and Corpus Christi LNG receiving terminals, at which the local communities have expressed support of our facilities.

Experienced Management Team with Significant Shareholdings. To pursue this business, we have assembled a team of professionals with extensive experience in the LNG industry. Through tenure with major oil companies, major operators of LNG receiving terminals and major engineering and construction companies, our senior management team has an average of more than 20 years of experience in the areas of LNG project development, operation, engineering, technology, transportation and marketing. Furthermore, our officers, directors and employees will beneficially own approximately 17% of our shares outstanding after this offering. We believe that such ownership provides appropriate incentive for our employees to increase shareholder value and serves to align their interests with those of our shareholders.

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The offering

Issuer		Cheniere Energy, Inc.
Common stock offered		5,000,000 shares
Common stock to be outstanding after this offering		25,359,758 shares(1)
Use of proceeds		We intend to use the net proceeds from this offering to fund the equity requirements of the project financing for our Sabine Pass LNG receiving terminal.
		If we enter into an agreement with Chevron USA or other parties to invest in Sabine Pass LNG, the net proceeds from this offering not needed for Sabine Pass LNG will be available to fund investments in other projects, including Corpus Christi LNG.
		We will use any proceeds from this offering not used in the manner described above for general corporate purposes, including funding potential additional LNG terminals, such as Creole Trail, and other projects, as well as possible expansions, cost overruns or cost increases at our projects. Pending such uses, we may invest such net proceeds in short-term, interest-bearing securities or accounts.
American Stock Exchange symbol		"LNG"

(1)

The number of shares of common stock to be outstanding after this offering excludes:

•: 1,640,832 shares of common stock issuable upon the exercise of outstanding options and warrants at a weighted average exercise price of $8.96 per share; and
•: 156,324 additional shares of common stock that are reserved for future grants, awards or sale under our current stock plan. We expect to propose a new stock plan for approval at the annual meeting of our stockholders in the spring of 2005.

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Risk factors

Investing in our common stock involves a high degree of risk. Before deciding to invest in shares of our common stock, you should carefully consider the following risk factors, the risk factors included under the caption "Risk factors" beginning on page 6 of the accompanying prospectus and those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended by Amendment Nos. 1 and 2 thereto, which are incorporated by reference into this prospectus supplement and the accompanying prospectus. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment in our common stock.

The risk factors in this prospectus supplement are grouped into the following categories:

•: Risks relating to our financial matters, beginning on this page S-9;
•: Risks relating to our LNG receiving terminal development business, beginning on page S-11;
•: Risks relating to our business in general, beginning on page S-16;
•: Risks relating to our common stock, beginning on page S-19; and
•: Risks relating to our oil and gas exploration and production business, referenced on page S-21.

Risks relating to our financial matters

We have not been profitable historically, and we are currently experiencing negative operating cash flow. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.

From our inception, we have incurred losses, and we will likely continue to incur operating losses and experience negative operating cash flow during the next several years. We have not yet started the construction of any of our planned LNG receiving terminals. We do not anticipate that our LNG receiving operations will generate positive operating cash flow until at least one of our planned facilities is built, which will not be until late 2007 at the earliest. Although we may commence operations, revenues under any particular TUA may not commence for up to one year after operations at the related facility commence. We will continue to incur significant capital and operating expenditures while we develop our planned LNG receiving terminals. We do not anticipate that our oil and gas exploration activities, which are limited in scope, or advance sales of regasification capacity at our planned LNG receiving terminals will generate sufficient funds to cover these expenditures. As a result, we expect to continue to have operating losses and negative operating cash flow on a quarterly and an annual basis over the next several years. Any delays beyond the expected development periods for our planned LNG receiving terminals would prolong, and could increase the level of, our operating losses and negative operating cash flow. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully complete our LNG development projects, and our ability to do so is subject to a number of risks, including those discussed below.

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Our ability to develop our planned LNG receiving terminals is contingent on our ability to obtain financing. If we are unable to do so, we may be unable to implement or complete our business plan and our business may ultimately be unsuccessful.

We currently estimate that the cost of completing our three LNG development projects will exceed $2.0 billion. As of September 30, 2004, we had only $9.3 million of current assets and working capital of $6.4 million, and currently we do not have a credit facility. As a result, to fund these development projects, we will have to obtain multiple types of financing, including most, if not all, of the following: debt and equity financing at the project level, debt and equity financing by Cheniere and asset sales by Cheniere. Our ability to obtain these types of financing will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects are otherwise proceeding on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project developer. As a result, even if we are able to identify potential project-level lenders, we will still have to obtain another form of external financing for us to fund an equity capital contribution. Any project-level debt financing will also typically be conditioned upon our prior receipt of commitments for a portion of projected regasification capacity under long-term TUAs. A failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.

Even if we are able to obtain financing, the terms required may adversely affect our business.

In order to obtain many types of financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our current or future business, operations or financial condition. For example:

•: borrowings or debt issuances by Cheniere may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital;
•: borrowings or debt issuances at the project level may subject the project entity to certain restrictive covenants, including covenants restricting its ability to make distributions to us;
•: additional sales of interests in our LNG projects would reduce our interest in future revenues once the LNG receiving terminals commence operations;
•: the prepayment of terminal use fees by, or a business development loan from, prospective customers would reduce future revenues once the LNG receiving terminals commence operations;
•: additional offerings of our equity securities would cause dilution of our common stock; and
•: sales of oil and gas exploration prospects would reduce potential future revenues from our exploration and production activities.

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Risks relating to our LNG receiving terminal development business

The construction of our planned LNG receiving terminals is subject to a number of development risks, which could cause cost overruns and delays or prevent completion of one or more of our LNG development projects.

Key factors that may affect the timing of, and our ability to complete, our LNG development projects include, but are not limited to:

•: the issuance of necessary permits, licenses and approvals from FERC, other governmental agencies and third parties as are required to construct and operate the facilities;
•: the availability of sufficient debt financing and equity financing, both on the part of Cheniere and at the project level;
•: our ability to obtain satisfactory long-term TUAs with "anchor tenant" customers for an adequate portion of the capacity at each proposed LNG receiving terminal and for these customers to perform under those TUAs;
•: our ability to enter into a satisfactory agreement with an EPC contractor for each facility and to maintain good relationships with these contractors;
•: site development difficulties, including change orders, cost overruns, construction delays and changes in commodity prices (particularly steel);
•: unanticipated changes in domestic and international market demand for natural gas or the supply of LNG;
•: competition with other domestic and international LNG receiving terminals;
•: commercial arrangements for pipelines and related equipment to transport natural gas from each LNG receiving terminal;
•: securing the participation of potential new project-level equity partners;
•: local and general economic conditions;
•: catastrophes, such as explosions, fires and product spills;
•: resistance in the local community to the development of LNG receiving terminals;
•: labor disputes; and
•: weather conditions.

Delays in the construction of an LNG receiving terminal beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts currently estimated in our capital budget, which could require us to obtain additional sources of financing to fund our operations until the LNG receiving terminal is developed (which could cause further delays). Any delay in completion of the LNG receiving terminals would also cause a delay in the receipt of revenues projected from operation of the facilities. Delays could also erode our competitive advantage of being one of the first companies to develop new LNG receiving terminals. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition and prospects.

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Failure to obtain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminal business would have a detrimental effect on our LNG projects and on our company.

The design, construction and operation of LNG receiving terminals and the transportation of LNG and natural gas are all highly regulated activities. FERC approval under Section 3 of the Natural Gas Act of 1938, or the NGA, as well as several other material governmental and regulatory approvals and permits, is required in order to construct and operate our proposed LNG receiving terminals. Although we have obtained NGA Section 3 authorization to construct and operate the Freeport LNG receiving terminal, subject to specified conditions that must be satisfied prior to commencement of construction, we have not yet received an NGA Section 3 FERC order authorizing construction of either our Sabine Pass or Corpus Christi projects. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed LNG receiving terminals. We have no control over the outcome of the review and approval process. If we are unable to obtain the necessary approvals and permits, we may not be able to recover our investment in the project. Failure to obtain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.

We face competition in the LNG receiving terminal development business from competitors with far greater resources and the potential for overcapacity in the LNG receiving terminal marketplace.

There are many companies looking to build infrastructure in the domestic LNG market, including, without limitation, major oil and gas companies such as ExxonMobil, ConocoPhillips, Royal Dutch/Shell and ChevronTexaco. Other energy companies such as Sempra, Tractebel, McMoRan Exploration, AES, Excelerate Energy and other public and private companies have also proposed facilities, both onshore and offshore. Almost all of our competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do. The superior resources that these competitors have available to deploy could allow them to surpass us in terms of the status of their LNG receiving terminal development projects. Among other things, these competitors may not have to rely on external financing to the same extent we do, if at all. Industry analysts have predicted that if all of the proposed LNG receiving terminals in North America that have been announced by developers were actually built, there would likely be substantial excess capacity for such terminals in the future. Accordingly, there is a substantial risk that slower-paced LNG receiving terminal development projects may never be completed. Any perception in the LNG receiving terminal marketplace that we may be unable to complete our proposed LNG receiving terminals, because competing projects are further along in their development or otherwise, could have a material adverse effect on our business, results of operations, financial condition and prospects.

In addition, our proposed LNG receiving terminals will likely continue to face competition when and if they are completed. If the number of LNG receiving terminals built outstrips demand, the excess capacity will likely lead to a decrease in the prices that we will be able to obtain for uncommitted amounts of our regasification services. Because of the substantial likelihood that we will have significant debt service obligations, any such price decreases would impact us more severely than our competitors with greater financial resources. Accordingly,

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potential overcapacity in the LNG receiving terminal marketplace could have a material adverse effect on our business, results of operations, financial condition and prospects.

Failure of imported LNG to become a competitive source of energy in the United States could have a detrimental effect on our ability to implement and complete our business plan.

In the United States, due mainly to an abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based on the belief that LNG can be produced and delivered to the United States at a lower cost than the cost to produce some domestic supplies of natural gas. Through the use of improved exploration technologies, additional sources of natural gas may be discovered in North America, which would further increase the available supply of natural gas at a lower cost than LNG. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. As a result, LNG may not become a competitive source of energy in the United States. The failure of LNG to become a competitive supply alternative to domestic natural gas, oil and other import alternatives could have a material adverse effect on our business, results of operations, financial condition and prospects.

The inability to import LNG into the United States would materially adversely affect our business plans and results of operations.

Upon completion of the LNG receiving terminals, our business will be dependent upon the ability of our customers to import LNG into the United States. Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the United States, may impede the willingness or ability of LNG suppliers in such countries to export LNG to the United States. Such foreign suppliers may also be able to negotiate more favorable prices with other LNG customers around the world than with customers in the United States, thereby reducing the supply of LNG available to be imported into the United States market. In addition, we believe that the existing fleet of tankers that is available to transport LNG is inadequate, and the failure to expand LNG tanker capacity would impede our customers' ability to import LNG into the United States. Any significant impediment to the ability to import LNG into the United States could have a material adverse affect on our business, results of operations, financial condition and prospects.

We may have difficulty obtaining enough customers for regasification capacity at our proposed LNG receiving terminals to implement and complete our business plan.

Our marketing strategy calls for us to enter into long-term TUAs covering a significant portion of the regasification capacity at each of our LNG receiving terminals, including a commitment to pay capacity reservation fees, prior to the commencement of construction of each facility. Our ability to obtain project-level financing for each LNG receiving facility may be contingent on our ability to enter into long-term TUAs covering a sufficient portion of regasification capacity in advance of the commencement of construction. In addition, we anticipate that we will be able to rely on these capacity reservation fee payments to cover a portion of operating costs prior to commencement of operations at our proposed LNG receiving terminals. The TUA with Chevron USA for our Sabine Pass LNG terminal will terminate if final corporate approvals, including approval by ChevronTexaco's board of directors, are not obtained by December 20, 2004. In addition, we do not have any TUAs in place for our proposed Corpus Christi facility.

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We may experience difficulty attracting additional customers because we are a small, developing company with no operating history in the LNG receiving terminal business. In order to succeed, we must convince additional potential customers that the terminal sites that we are developing will be approved by appropriate governmental agencies and that we will be able to secure adequate financing for their construction. If these efforts are not successful, our business, results of operations, financial condition and prospects could be materially adversely affected.

Decreases in the price of natural gas in North America could be harmful to our ability to develop our proposed LNG receiving terminals.

The development of domestic LNG receiving terminals is based on assumptions about the future price of natural gas and the availability of imported LNG. The willingness of potential customers to contract for regasification capacity would be negatively impacted and, once facilities are in operation, LNG throughput volumes would likely decline if the price of natural gas in North America is, or is forecasted to be, lower than the cost to produce and deliver LNG to North American markets. Any significant decline in the price of natural gas could cause the cost of natural gas produced from imported LNG to be higher than domestically produced natural gas. As a result, any significant decline in the price of natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.

Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to any of the following factors:

•: relatively minor changes in the supply of, and demand for, natural gas;
•: political conditions in international natural gas producing regions;
•: the extent of domestic production and importation of natural gas in relevant markets;
•: the level of consumer demand;
•: weather conditions;
•: the competitive position of natural gas as a source of energy as compared with other energy sources; and
•: the effect of federal and state regulation on the production, transportation and sale of natural gas.

Our TUAs are subject to termination by our contractual counterparties under certain circumstances, and we are generally dependent on the performance of those counterparties under the TUAs.

Freeport LNG has entered into long-term TUAs with Dow and ConocoPhillips, and Sabine Pass LNG has entered into long-term TUAs with subsidiaries of Total S.A. and ChevronTexaco. Each of the TUAs contains various termination rights. For example, the TUA with Chevron USA is subject to final corporate and board approval on or before December 20, 2004, or it will terminate. Dow may terminate its TUA during the construction period of the proposed Freeport LNG terminal if it reasonably determines that "substantial completion" of the terminal will not occur prior to a future confidential date. Similarly, ConocoPhillips may terminate its TUA during the construction period of the proposed Freeport LNG terminal if it reasonably

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determines that the "conversion date" (the date of conversion of construction loans into term loans under the credit facility between Freeport LNG and ConocoPhillips) will not occur prior to a future confidential date. Total has the right to terminate its TUA under an omnibus agreement if specified conditions are not satisfied by June 30, 2005, including issuance of an order by FERC authorizing construction of the facility and evidence of the ability to finance construction of the facility. Total may also terminate its TUA with Sabine Pass if the debt-to-equity ratio of Sabine Pass LNG exceeds 80/20 for more than 15 days or, if Sabine Pass LNG has obtained credit ratings, two of its credit ratings fall below a "B2" by Moody's or the equivalent for more than 15 days and the debt-to-equity ratio of Sabine Pass LNG on the 15^th day exceeds 80/20. In addition, in the case of each of our TUAs, we are dependent on the respective counterparties' willingness to perform their obligations under the TUAs. If any of these counterparties fail to perform under its respective TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if we were to be ultimately successful in seeking damages from that counterparty for a breach of the TUA.

The construction of our proposed LNG receiving terminals will be dependent on performance by, and our relationship with, the EPC contractor that we engage at each facility.

We are in ongoing negotiations with a major international EPC contractor to enter into a lump-sum, turnkey contract for the construction of our proposed Sabine Pass LNG receiving terminal. Freeport LNG is negotiating with a major international EPC contractor for the construction of the proposed Freeport LNG receiving terminal. We also plan to enter into similar types of contracts with a major international EPC contractor for the construction of our proposed Corpus Christi LNG receiving terminal. The success of our LNG receiving terminal development projects is highly dependent on our ability to enter into acceptable contracts with reputable EPC contractors and for the EPC contractors to perform their obligations under the contracts, including completing the projects on a timely basis. However, we may not be able to enter into an acceptable contract with any EPC contractor. In addition, we have no prior experience working with any EPC contractor. As a result, even if we enter into acceptable contracts, we may encounter unexpected delays or problems in connection with the construction of any of our proposed LNG receiving terminals. If our relationship with any initial EPC contractor fails for any reason, we would be forced to engage a substitute contractor, which would likely result in a significant delay in our development schedule and could have a material adverse effect on our business, results of operations, financial condition and prospects.

The cost of constructing our proposed LNG receiving terminals will be dependent on several contingencies, including change orders, cost overruns and commodity prices. As a result, if completed, the actual construction cost of these facilities may be significantly higher than our current estimates.

We do not have any prior experience in constructing LNG receiving terminals, and no LNG receiving terminal has been constructed in the United States in over 25 years. As construction progresses, we may decide or be forced to submit change orders to our EPC contractor that could result in a longer construction period and higher construction costs. Similarly, we may encounter significant cost overruns during some phases of the construction process. In addition, under any agreement with an EPC contractor, we expect to retain the commodity price risk for nickel and various types of steel used in the construction process. As a result, any significant

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change orders, cost overruns or increases in the commodity price of nickel or steel could have a material adverse effect on our business, results of operations, financial condition and prospects.

Risks relating to our business in general

We are currently a small, developing company with no operating history in the LNG receiving terminal business. Our business model is contingent on our ability to manage successfully our anticipated expansion and transition to operating in that business.

We currently have 41 employees, who, for the most part, are focused on the pre-construction stages of the development of our proposed LNG receiving terminals. As we begin construction of the LNG receiving terminals, we will have to hire new onsite employees to manage the construction of each facility. Later, once our proposed LNG receiving terminals commence operations, we will have to hire an entire staff to operate each facility. We have no experience in the construction or operation of LNG receiving terminals, and, as a result, we will be forced to rely to a significant extent on the new employees we hire to perform these functions. We currently estimate that at least 60 employees will be required to operate each LNG receiving terminal. As our operations expand, we will also have to expand our administrative staff. If we are not able to successfully manage the expansion of our business, our business, results of operation, financial condition and prospects could be materially adversely affected.

We depend on key personnel, and we could be seriously harmed if we lost their services.

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have agreements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us. In addition, our future success will depend in part on our ability to attract and retain additional qualified personnel.

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

The construction and operation of our proposed LNG receiving terminals will be subject to the inherent risks normally associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damage to persons and property. In addition, our operations face possible risks associated with acts of aggression on our assets and the assets of third parties on which our operations are dependent.

In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses. We may not be able to maintain adequate 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, results of operations, financial condition and prospects.

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Existing and future United States governmental regulation, taxation and price controls could seriously harm us.

Our LNG terminal development operations are subject to extensive federal, state and local laws and regulations that regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Failure to comply with such rules and regulations can result in substantial penalties and may harm us. Present, as well as future, legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

The construction and operation of our LNG receiving terminals is subject to issuance of necessary permits, licenses, consultations and approvals from numerous federal agencies, including from FERC regulation under Section 3 of the NGA. The costs that we incur to obtain FERC and other governmental approvals authorizing us to commence construction of our proposed LNG receiving terminals and to comply with the ongoing regulation of such terminals could have a material adverse effect on our business, results of operations, financial condition and prospects. In addition, delay in receipt of FERC or other required governmental authorization could cause substantial delays in the commencement of construction or operations of our LNG receiving terminals or even result in the cessation of operations. Any interstate pipeline transmission system connected to our LNG receiving terminals, as will be the case with our proposed Sabine Pass and Corpus Christi terminals, is subject to FERC regulation under Section 7 of the NGA. Such regulation may restrict the ability of our customers to transport gas to and from our terminals, which could have a material adverse effect on our business, results of operations, financial condition and prospects. FERC has in the past regulated the prices at which oil and natural gas could be sold. Federal reenactment of price controls or increased regulation of the transport of oil and natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our LNG terminal development operations are also subject to extensive federal, state and local laws and regulations governing the discharge of natural gas and hazardous materials into the environment or otherwise relating to environmental protection. These laws and regulations may restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and impose substantial liabilities for pollution or releases of hazardous substances. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. Moreover, state and federal environmental laws and regulations may become more stringent.

Federal laws and regulations such as the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Clean Air Act, or CAA, the Oil Pollution Act of 1990, or OPA, and the Clean Water Act, or CWA, and analogous state laws have regularly imposed increasingly strict requirements for water and air pollution control, solid waste management and strict financial responsibility and remedial response obligations. The cost of complying with such environmental legislation could have a material adverse effect on our business, results of operations, financial condition and prospects.

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not fully recoverable from insurance or our customers, could have a material adverse effect on our business, results of operations, financial condition and prospects.

Some of our economic value is derived from our ownership of minority interests in entities over which we exercise no day-to-day control.

We own a 30% limited partner interest in Freeport LNG, an effective 9.3% interest in Gryphon Exploration (after giving effect to the potential conversion of Gryphon Exploration's preferred stock) and a minority interest in J&S Cheniere. Some of our value is attributable to these investments. In this prospectus supplement, we may use the words "our," "we" or "us" in describing these investments or their assets and operations; however, we do not exercise control over Freeport LNG, Gryphon Exploration or J&S Cheniere. The management team of Freeport LNG, Gryphon Exploration or J&S Cheniere could make business decisions without our consent that could impair the economic value of our investments in those entities. Any such diminution in the value of either investment could have an adverse impact on our business, results of operations, financial condition and prospects.

We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. A company may be deemed to be an investment company if it owns investment securities with a value exceeding 45% of the value of its total assets (excluding government securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own minority equity interests in certain entities that could be counted as investment securities. If the value of our minority interests in these entities exceeds 45% of the value of our total assets (excluding government securities and cash items), we could be considered an investment company in the future if we do not obtain an exemption or qualify for a safe harbor. As a result, fluctuations in the value, or the income and revenues attributable to us from our ownership of interests in companies that we do not control could cause us to be deemed an investment company. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy. We may have to take actions, including buying, refraining from buying, selling or refraining from selling securities or other assets, contrary to what we would otherwise deem to be in our best interest, in order to continue to avoid registration under the Investment Company Act.

Terrorist attacks or sustained military campaigns may adversely impact our business.

The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. The continued threat of terrorism and the impact of military and other action will likely lead to continued volatility in prices for natural gas and could affect the markets for the operations of our LNG customers on which we will be dependent. Furthermore, the United States government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist

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organizations. The continuation of these developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.

Risks relating to our common stock

Our common stock has experienced, and may continue to experience, significant price volatility.

The trading price of our common stock has been, and may continue to be, subject to large fluctuations, which may result in losses to investors. Our stock price may increase or decrease in response to a number of events, including:

•: our progress, or lack thereof, with respect to the development of our LNG receiving terminals;
•: trends in our industry and the markets in which we operate;
•: changes in financial estimates and recommendations by securities analysts;
•: acquisitions and financings;
•: quarterly variations in operating results;
•: the operating and stock price performance of other companies that investors may deem comparable; and
•: purchases or sales of blocks of our common stock.

This volatility may adversely affect the price of our common stock regardless of our operating performance.

We expect to make announcements, including within the next month, that may significantly affect our stock price.

Because we are a small, developing company, with no history of operations in the LNG receiving terminal business, the trading price of our common stock, in the near term, is likely to be closely linked to the progress we make and announce with respect to our LNG receiving terminal development projects. We have recently made announcements concerning the development of our proposed Sabine Pass receiving terminal, including announcements that we have entered into a long-term TUA with Chevron USA, subject to final corporate and board approval on their part, and that we are negotiating with Chevron USA about making a $200 million equity investment in our Sabine Pass development project in exchange for a 20% equity interest. We expect to learn by December 20, 2004 whether the Chevron USA TUA receives final corporate approvals, including approval by ChevronTexaco's board of directors, and whether they will make the proposed equity investment. We have also stated publicly that, by the end of 2004, we expect that FERC will issue an order authorizing construction of our proposed Sabine Pass LNG receiving terminal. If ChevronTexaco does not approve either the TUA or the equity investment, or if we do not receive an order from FERC by the end of the year as anticipated, our announcement of any of those events could cause a significant decline in our stock price.

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Common shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is performing well.

Our directors and executive officers have agreed not to sell any of their shares of common stock for a period of 90 days following this offering, but these "lock-up" agreements are subject to certain exceptions, as described in "Underwriting". If our existing stockholders sell our common stock in the market following this offering, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly. In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired. In order to finance all of our LNG receiving terminal development projects, we anticipate that we will have to issue additional shares of our common stock in the future, in public underwritten offerings or in other types of transactions. If we are unable to do so because of a decline in our stock price or market conditions generally, our business, results of operations, financial condition and prospects could be materially adversely affected.

Additional issuances of common stock will also dilute the ownership percentages of existing stockholders and their share of any future earnings. Our board of directors has the authority to issue additional shares of our authorized but unissued common stock without the approval of our stockholders.

Some anti-takeover measures contained in our restated certificate of incorporation, amended and restated by-laws and stockholders rights agreement, as well as provisions of Delaware law, could impair a takeover attempt.

We have provisions in our restated certificate of incorporation and amended and restated by-laws, each of which could have the effect of rendering more difficult or discouraging an acquisition deemed undesirable by our board of directors. These include provisions:

•: authorizing blank check preferred stock, which could be issued with voting, liquidation, dividend and other rights superior to its common stock;
•: providing for a classified board of directors;
•: limiting the liability of, and providing indemnification to, directors and officers;
•: limiting the ability of our stockholders to call special meetings;
•: requiring advance notice of stockholder proposals for business to be conducted at meetings of our stockholders and for nominations of candidates for election to our board of directors;
•: controlling the procedures for conduct of board and stockholder meetings and election and removal of directors; and
•: specifying that stockholders may take action only at a duly called annual or special meeting of stockholders.

In addition, on October 13, 2004, our board of directors adopted a stockholder rights plan in which preferred stock purchase rights, or Rights, were distributed as a dividend at the rate of one Right for each share of common stock of Cheniere held by stockholders of record as of the close of business on November 1, 2004. The Rights will expire on October 14, 2014. While not

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initially exercisable, each Right will entitle stockholders to buy one unit of a share of preferred stock for $200, subject to adjustment. The Rights generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of our common stock or commences a tender or exchange offer upon consummation of which the person or group would beneficially own 15% or more of our common stock. After the occurrence of such an event, each Right will entitle its holder (other than such persons or group) to receive, upon exercise, units of a share of preferred stock having a value equal to two times the then-current exercise price.

These anti-takeover measures, alone or together, could deter or delay hostile takeovers, proxy contests and changes in control or management, could limit opportunities for our stockholders to receive a premium for their shares of our common stock and could also affect the price that some investors are willing to pay for our common stock. As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders from engaging in certain business combinations without approval of the holders of substantially all of our outstanding common stock.

Risks relating to our oil and gas exploration and production business

We have not included any risk factors relating to our oil and gas exploration and production business in this prospectus supplement. For information about the risks associated with our oil and gas exploration and production business, we refer you to the risk factors beginning on page 8 of the accompanying prospectus and the risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended by Amendment Nos. 1 and 2 thereto, which are incorporated by reference into this prospectus supplement and the accompanying prospectus.

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Forward-looking statements

This prospectus supplement contains certain statements that may include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included herein or incorporated herein by reference are "forward-looking statements." Included among "forward-looking statements" are, among other things:

•: statements that we expect to commence or complete construction of each of our proposed LNG receiving terminals by certain dates, or at all;
•: statements that we expect to receive Draft Environmental Impact Statements or Final Environmental Impact Statements from FERC by certain dates, or at all, or that we expect to receive an order from FERC authorizing us to construct and operate proposed LNG receiving terminals by a certain date, or at all;
•: statements regarding future levels of domestic natural gas production and consumption or the future level of LNG imports into North America, regardless of the source of such information;
•: statements regarding any financing transactions or arrangements, whether on the part of Cheniere or at the project level, including financing arrangements for which we may have received commitment letters;
•: statements relating to the construction of our proposed LNG receiving terminals, including statements concerning the engagement of any EPC contractor and the anticipated terms and provisions of any agreement with an EPC contractor;
•: statements regarding any TUA or other agreement to be performed substantially in the future, including any cash distributions and revenues anticipated to be received;
•: statements regarding the potential sale of equity interests in any of our LNG receiving terminal development projects or any other possible equity or asset sales;
•: statements that our proposed LNG receiving terminals, when completed, will have certain characteristics, including amounts of regasification and storage capacities, a number of storage tanks and docks and pipeline interconnections;
•: statements regarding possible expansions of the currently projected size of any of our proposed LNG receiving terminals;
•: statements regarding our business strategy, our business plan or any other plans, forecasts or objectives; and
•: any other statements that relate to non-historical information.

These forward-looking statements are often identified by the use of terms and phrases such as "achieve," "anticipate," "believe," "estimate," "expect," "forecast," "plan," "project," "propose" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.

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Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in "Risk factors" beginning on page S-9 of this prospectus supplement and page 6 of the accompanying prospectus and those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended by Amendment Nos. 1 and 2 thereto, which are incorporated by reference into this prospectus supplement and the accompanying prospectus. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements.

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Use of proceeds

Our net proceeds from the sale of shares by us in this offering will be approximately $286.1 million, after deducting underwriting discounts and estimated offering expenses payable by us. We intend to use the net proceeds from this offering to fund the equity requirements of the project financing for our Sabine Pass LNG receiving terminal.

If we enter into an agreement with Chevron USA or other parties to invest in Sabine Pass LNG, the net proceeds from this offering not needed for Sabine Pass LNG will be available to fund investments in other projects, including Corpus Christi LNG.

We will use any proceeds from this offering not used in the manner described above for general corporate purposes, including funding potential additional LNG terminals and other projects, as well as possible expansion, cost overruns or cost increases at our projects. Pending such uses, we may invest such net proceeds in short-term, interest-bearing securities or accounts.

Dividend policy

We have not paid cash dividends on our common stock and do not anticipate paying dividends in the foreseeable future. Our board of directors currently intends to retain any future earnings for reinvestment in our business. In any event, any determination to pay dividends will be at the discretion of our board of directors and will be dependent upon our results of operations and cash flows, our financial position and capital requirements, general business conditions, legal, tax, regulatory and any contractual restrictions on the payment of dividends and any other factors that our board of directors deems relevant.

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Price range of common stock

As of December 1, 2004, there were 20,359,758 shares of our common stock outstanding, held by approximately 5,300 holders, including shares held in street name. Our common stock is traded on the American Stock Exchange under the symbol "LNG".

The following table sets forth, for the periods indicated, the high and low closing sales price for shares of our common stock, as reported on the American Stock Exchange. The closing sales price of our common stock on the American Stock Exchange on December 2, 2004 was $61.85 per share.

		Price Ranges

		High		Low

2004
	Fourth Quarter (through December 2, 2004)	$	62.30	$	20.13
	Third Quarter	$	20.84	$	16.25
	Second Quarter	$	20.84	$	11.07
	First Quarter	$	19.08	$	11.11
2003
	Fourth Quarter	$	11.90	$	5.05
	Third Quarter	$	6.03	$	4.29
	Second Quarter	$	5.10	$	1.39
	First Quarter	$	1.60	$	1.20
2002
	Fourth Quarter	$	1.35	$	0.80
	Third Quarter	$	1.30	$	0.90
	Second Quarter	$	1.50	$	0.82
	First Quarter	$	1.50	$	0.93
2001
	Fourth Quarter	$	1.25	$	0.75
	Third Quarter	$	2.19	$	0.90
	Second Quarter	$	2.88	$	1.85
	First Quarter	$	3.38	$	2.09

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Capitalization

The following table sets forth our cash and our consolidated capitalization as of September 30, 2004:

•: on an actual basis; and
•: on an as adjusted basis to reflect the sale of 5,000,000 shares of our common stock in this offering, and our receipt of the net proceeds from this offering after payment of expenses directly associated with this offering.

You should read the data set forth below in conjunction with "Management's discussion and analysis of financial condition and results of operations" beginning on page S-29.

				As of September 30, 2004(1)

				Actual			As Adjusted

Cash and cash equivalents				$	7,126,266		$	293,196,266

Debt				$	—		$	—

Stockholders' equity:
	Preferred stock, $0.001 par value, 5,000,000 shares authorized, none issued and outstanding, actual; 5,000,000 shares authorized, none issued and outstanding, as adjusted				—			—
	Common stock, $0.003 par value, 40,000,000 shares authorized, 19,761,154 shares issued and outstanding, actual; 40,000,000 shares authorized, 24,761,154 shares issued and outstanding, as adjusted(2)				59,284			74,284
	Additional paid-in capital				72,906,607			358,961,607
	Deferred compensation				(2,553,333	)		(2,553,333	)
	Accumulated deficit				(43,711,965	)		(43,711,965	)

		Total stockholders' equity			26,700,593			312,770,593

			Total capitalization	$	26,700,593		$	312,770,593

(1)

Subsequent to September 30, 2004, Sabine Pass LNG received advance capacity reservation fee payments of (i) $10 million from Total in connection with Total's exercise of an option to reserve 1.0 Bcf/d of LNG regasification capacity and (ii) $5 million from Chevron USA in connection with the execution of a TUA for as much as 1.0 Bcf/d of LNG regasification capacity. We will record these amounts as deferred revenue, which will be amortized over a ten-year period commencing upon the start of operations at our Sabine Pass facility.

(2)

The number of shares of common stock to be outstanding after this offering excludes:

•: 1,640,832 shares of common stock issuable upon the exercise of outstanding options and warrants at a weighted average exercise price of $8.96 per share; and
•: 156,324 additional shares of common stock that are reserved for future grants, awards or sale under our current stock plan. We expect to propose a new stock plan for approval at the annual meeting of our stockholders in the spring of 2005.

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Summary selected consolidated financial data

You should read the following summary selected consolidated financial data together with our financial statements and the related notes appearing in our annual report on Form 10-K for the year ended December 31, 2003, as amended on Form 10-K/A by Amendment Nos. 1 and 2 thereto, and quarterly report on Form 10-Q for the quarter ended September 30, 2004, which are incorporated by reference into this prospectus supplement and the accompanying prospectus, and the "Management's discussion and analysis of financial condition and results of operations" beginning on page S-29 of this prospectus supplement. We have derived the statement of operations data for the nine months ended September 30, 2003 and 2004 and the balance sheet data at September 30, 2004 from our unaudited financial statements which are incorporated by reference into this prospectus supplement and the accompanying prospectus. The unaudited financial statements have been prepared on the same basis as the audited financial statements and, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation of the information set forth therein. We have derived the statement of operations data for the years ended December 31, 2001, 2002 and 2003, and the balance sheet information at December 31, 2003 from our audited financial statements which are incorporated by reference into this prospectus supplement and the accompanying prospectus.

		Year Ended December 31,									Nine Months Ended September 30,

		2001			2002			2003			2003			2004

Revenues		$	2,372,632		$	239,055		$	657,467		$	366,665		$	1,132,240
Production costs			420,242			90,038			—			—			29,184
Depreciation, depletion and amortization			1,243,828			368,562			428,680			251,006			631,956
Ceiling test write-down			5,126,248			—			—			—			—
General and administrative expenses
	LNG terminal development		1,788,419			1,556,782			6,704,538			3,360,643			12,664,635
	Other		2,503,544			1,918,580			2,542,399			1,728,055			7,856,586
Loss from operations			(8,709,649	)		(3,694,907	)		(9,018,150	)		(4,973,039	)		(20,050,121	)
Interest income			18,578			7,733			2,740			2,288			48,283
Equity in net loss of affiliate(1)			(2,974,191	)		(2,184,847	)		—			—			—
Equity in net income (loss) of limited partnership(2)			—			—			(4,471,529	)		(2,655,635	)		84,473
Gain on sale of oil and gas properties			—			340,257			—			—			—
Gain on sale of LNG assets			—			—			4,760,000			4,760,000			—
Gain on sale of limited partnership interests			—			—			423,454			423,454			—
Reimbursement from limited partnership investment(3)			—			—			—			—			2,500,000
Minority interest(4)			—			—			3,015,468			1,552,978			2,650,210
Loss on extinguishment of debt			—			(100,544	)		—			—			—
Net loss		$	(11,665,262	)	$	(5,632,308	)	$	(5,288,017	)	$	(889,954	)	$	(14,767,155	)
Net loss per share (basic and diluted)		$	(0.89	)	$	(0.42	)	$	(0.36	)	$	(0.06	)	$	(0.79	)
Cash dividends per share			—			—			—			—			—
Weighted average shares outstanding (basic and diluted)			13,035,256			13,297,393			14,771,700			14,306,270			18,768,228

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	December 31, 2003		September 30, 2004


Cash	$	1,257,693	$	7,126,266
Working capital		155,526		6,372,798
Oil and gas properties, proved, net		1,087,152		1,024,793
Oil and gas properties, unproved		18,047,802		18,381,681
Total assets		24,590,757		30,883,376
Long-term notes payable		—		—
Total liabilities		4,331,826		2,894,063
Deferred revenue(5)		1,000,000		1,000,000
Minority interest		120,032		288,720
Total stockholders' equity		19,138,899		26,700,593

(1): Effective January 1, 2003, we began accounting for this investment in Gryphon using the cost method of accounting. The amounts listed for 2002 and 2001 represent our equity in the net loss of Gryphon under the equity method of accounting.
(2): Represents our equity in the net income (loss) of Freeport LNG.
(3): Represents cash reimbursement received after our investment in Freeport LNG was reduced to zero.
(4): Represents the minority interest of our partner in the net loss of Corpus Christi LNG.
(5): Subsequent to September 30, 2004, Sabine Pass LNG received advance capacity reservation fee payments of (i) $10 million from Total in connection with Total's exercise of an option to reserve 1.0 Bcf/d of LNG regasification capacity and (ii) $5 million from Chevron USA in connection with the execution of a TUA for as much as 1.0 Bcf/d of LNG regasification capacity. We will record these amounts as deferred revenue, which will be amortized over a ten-year period commencing upon the start of operations at our Sabine Pass facility.

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Management's discussion and analysis
of financial condition and results of operations

General

We are engaged primarily in the development of a LNG receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. The LNG receiving terminal business consists of receiving deliveries of LNG from LNG carriers, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers. We own interests in three limited partnerships that are developing LNG receiving terminals:

•: Freeport LNG, in which we own a 30% interest, is developing an LNG receiving terminal on Quintana, Island, near Freeport, Texas;
•: Sabine Pass LNG, in which we own a 100% interest, is developing an LNG receiving terminal near Sabine Pass in Cameron Parish, Louisiana; and
•: Corpus Christi LNG, in which we own a 66.7% interest, is developing an LNG receiving terminal near Corpus Christi, Texas.

Freeport LNG

Freeport LNG is developing an LNG receiving terminal with an anticipated regasification capacity of 1.5 Bcf/d. We developed this project and then sold a 60% limited partner interest to an affiliate of the general partner of Freeport LNG and a 10% limited partner interest to another unaffiliated party. We continue to own a 30% limited partner interest in Freeport LNG. Freeport LNG has received an order from FERC authorizing construction of the Freeport LNG facility, subject to specified conditions that must be satisfied prior to commencement of construction. We currently anticipate that construction will begin by the first quarter of 2005, with terminal operations to commence in late 2007.

In June 2003, Dow signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal beginning with commercial start-up of the facility in 2007. On March 1, 2004, Freeport LNG and Dow entered into a 20-year TUA providing for a firm commitment by Dow for the use of 250 Mmcf/d of regasification capacity. In August 2004, Dow exercised its option under the TUA and committed to an additional 250 Mmcf/d of regasification capacity for a total of 500 Mmcf/d of regasification capacity.

On December 21, 2003, ConocoPhillips and Freeport LNG signed an agreement under which ConocoPhillips would reserve 1.0 Bcf/d of regasification capacity in the Freeport LNG receiving terminal. ConocoPhillips would also obtain a 50% interest in the general partner of Freeport LNG and provide a substantial majority of the financing to construct the facility. Freeport LNG received a non-refundable capacity reservation fee of $10 million from ConocoPhillips in January 2004. The ConocoPhillips transaction closed in July 2004, at which time ConocoPhillips paid Freeport LNG an additional non-refundable $3.5 million to secure an option on 500 Mmcf/d of additional capacity in the event the terminal is expanded.

S-29

Sabine Pass LNG

Our 100%-owned limited partnership entity, Sabine Pass LNG, is developing an LNG receiving terminal with an anticipated regasification capacity of 2.6 Bcf/d. In November 2004, FERC issued the FEIS for our proposed Sabine Pass LNG receiving terminal. In the FEIS, FERC concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that, by the end of 2004, FERC will issue an order authorizing construction of the Sabine Pass LNG facility, subject to specified conditions that must be satisfied prior to commencement of construction. Construction is anticipated to begin in the first quarter of 2005, with terminal operations commencing in 2008.

On September 2, 2004, Sabine Pass LNG entered into a TUA to provide Total with 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. In November 2004, Total exercised its option to proceed with the transaction by delivering to Sabine Pass LNG (i) an advance capacity reservation fee payment of $10 million and (ii) a guarantee by Total S.A. of certain Total obligations under the TUA. Cheniere, Sabine Pass LNG and Total also entered into an omnibus agreement on September 2, 2004, under which the TUA remains subject to certain conditions described below under "Business—our LNG receiving terminals—Sabine Pass LNG—Total TUA."

The TUA provides for Total to pay a fee of $0.32 per Mmbtu, subject in part to adjustment for inflation, for 1.0 Bcf/d of regasification capacity for a 20-year period beginning not later than April 1, 2009. In addition, under the omnibus agreement, if Sabine Pass LNG enters into a new TUA with a third party, other than Cheniere affiliates, for capacity of 50 Mmcf/d or more, with a term of five years or more, prior to the commercial start date of the terminal, Total will have the option, exercisable within 30 days of the receipt of notice of such transaction, to adopt the pricing terms contained in such new TUA for the remainder of the term of the Total TUA.

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10 million will be payable to Sabine Pass LNG upon satisfaction of two conditions under the Total omnibus agreement: (i) approval by FERC of the pending application to build the Sabine Pass LNG receiving terminal; and (ii) evidence of the ability to finance construction of the facility, which will be deemed satisfied if Sabine Pass LNG has entered into a loan agreement with a creditworthy lender with sufficient equity to be contributed to the facility and an acceptable EPC contractor has accepted the notice to proceed with construction. Total has the right to terminate this transaction under the omnibus agreement if these conditions are not satisfied by June 30, 2005.

On November 8, 2004, Sabine Pass LNG entered into a TUA to provide Chevron USA with 700 Mmcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. Sabine Pass LNG and Chevron USA simultaneously entered into an omnibus agreement, under which Chevron USA agreed to make advance capacity reservation fee payments. The TUA and omnibus agreement remain subject to final corporate approvals, including approval by the ChevronTexaco board of directors, by December 20, 2004. We continue to negotiate with Chevron USA about making a $200 million equity investment to acquire a 20% limited partner interest in Sabine Pass LNG.

The TUA provides for Chevron USA to pay a fee of $0.32 per Mmbtu, subject in part to adjustment for inflation, for 700 Mmcf/d of regasification capacity for a 20-year period

S-30

beginning not later than July 1, 2009. Under the omnibus agreement, Chevron USA has the option, at the same fee, either to reduce its reserved capacity at Sabine Pass to 500 Mmcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005. ChevronTexaco will guarantee certain Chevron USA payment obligations under the TUA.

The omnibus agreement requires Chevron USA to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, beginning with an unconditional payment of $5 million that has been paid. Except for this $5 million payment, Chevron USA has the right to terminate the TUA, the omnibus agreement and the transactions under those agreements if final corporate approvals, including approval of ChevronTexaco's board of directors, are not obtained by December 20, 2004. If the agreements and transactions are not terminated, further advance capacity reservation fee payments will be due as described below under "—Liquidity and capital resources—LNG terminal development—Sabine Pass LNG".

HSBC and Société Générale have entered into agreements with us to arrange $741 million of non-recourse project debt financing, which we plan to use to fund a substantial majority of the Sabine Pass LNG terminal construction costs. The commitments of HSBC and Société Générale are subject to significant conditions, including due diligence, documentation, syndication, execution of a lump-sum turnkey EPC contract, execution of one or more TUAs for at least 1.0 Bcf/d of long-term capacity commitments and funding of adequate equity contributions to Sabine Pass LNG. We anticipate that the EPC contract we are currently negotiating and the TUA we have already finalized with Total will be acceptable to the lenders. We will fund the equity contribution required by the lenders with proceeds from this offering or, if applicable, with proceeds from equity invested in Sabine Pass LNG by Chevron USA or other parties. Chevron USA is currently negotiating with us about making a $200 million equity contribution for a 20% limited partner interest in Sabine Pass LNG. The results of such negotiations should be known by December 20, 2004, but there can be no assurance that such an agreement can be reached.

Corpus Christi LNG

We own a 66.7% limited partner interest in Corpus Christi LNG, which is developing an LNG receiving terminal with an anticipated regasification capacity of 2.6 Bcf/d. We are marketing 1.5 Bcf/d of capacity under long-term TUAs of $0.32 per Mmbtu, the same price contracted for at Sabine Pass. However, we cannot assure you that we will be able to obtain any TUAs for Corpus Christi on terms acceptable to us at that price, or at all. We currently anticipate that, by the second quarter of 2005, FERC will issue an order authorizing construction of this terminal, subject to specified conditions that must be satisfied prior to commencement of construction. Construction is anticipated to begin in the third quarter of 2005, with terminal operations commencing in 2009.

Other Activities

In November 2004, we announced the acquisition of an option on a proposed LNG site at the mouth of the Calcasieu Channel in Cameron Parish, Louisiana, which we refer to as Creole Trail LNG. We plan to develop Creole Trail in the same manner as our Sabine Pass LNG facility with two docks, three 160,000 cm storage tanks and an initial regasification capacity of 2.6 Bcf/d. We plan to begin the National Environmental Policy Act pre-filing process with FERC in January 2005 and expect the permitting process to take 12 to 18 months.

S-31

In December 2003, we entered into an option agreement with J & S Cheniere S.A., or J&S Cheniere (an entity in which we are a minority owner), providing J&S Cheniere with an option to purchase LNG regasification capacity of up to 200 Mmcf/d in each of our Sabine Pass and Corpus Christi LNG facilities. We were paid $1 million in connection with the execution of the option agreement by J&S Cheniere in January 2004. The option agreement may be terminated by J&S Cheniere and the option fee refunded in the event that FERC does not issue an order authorizing Cheniere LNG to construct at least one of the facilities, or if Cheniere LNG decides not to proceed with the development of at least one of the facilities, in either case, before December 15, 2005. J&S Cheniere may exercise the option as to each facility by entering into a TUA no later than 60 days after receipt of written notification by us that FERC has issued an order authorizing construction of at least one of the facilities and all other approvals and permits have been received that are necessary to begin construction of the facility.

We are pursuing additional potential LNG receiving terminal projects and are also engaged, to a lesser extent, in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

Liquidity and capital resources

LNG terminal development

We are primarily engaged in developing LNG receiving terminals. These LNG terminal projects will require very significant amounts of capital and are subject to risks and delays in completion. Even if successfully completed, these projects will not begin to operate and generate significant cash flows until several years from now. As a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct these LNG terminals, to bring them into operation on a commercially viable basis and to finance the costs of staffing, operating and expanding our company during that process.

We own a 100% interest in Sabine Pass LNG, a 66.7% limited partner interest in Corpus Christi LNG and a 30% limited partner interest in Freeport LNG. We currently estimate that, in the aggregate, these three terminal projects will require in excess of $2.0 billion to construct and place in service. In addition, we have other potential terminal and pipeline projects in different stages of development. These projects, if successfully pursued, will require comparable amounts of capital.

In January 2004, we initiated the marketing of regasification capacity for our proposed Sabine Pass and Corpus Christi LNG receiving terminals. We have been actively engaged in the marketing process since that time, seeking long-term contracts for our planned regasification capacity. Upon execution of each TUA, we typically receive an advance payment for regasification capacity sold. This provides additional capital to help meet our ongoing liquidity needs. Furthermore, each TUA will serve as collateral to facilitate project level debt financing that we intend to obtain with respect to the construction of the related LNG receiving terminal.

As of September 30, 2004, we had working capital of $6,372,798. In November 2004, we received advance payments of $10 million from Total and $5 million from Chevron USA for capacity reservations at our Sabine Pass facility under agreements through which we will receive an additional $10 million from Total and an additional $15 million from Chevron USA if

S-32

specified conditions are satisfied. We must augment these sources of cash with significant additional funds in order to carry out our business plan.

We currently expect that capital requirements for our three current LNG terminal projects will be financed in part through issuances of project-level debt, equity or a combination of the two and in part with net proceeds of debt or equity securities issued by Cheniere or other Cheniere borrowings. Our financing plans and anticipated capital requirements for our three current LNG terminal development projects follow.

Freeport LNG

We developed the Freeport LNG project and received cash proceeds of $9,073,759 in connection with the disposition of a 60% limited partner interest to an affiliate of the general partner of Freeport LNG and the disposition of a 10% limited partner to another unaffiliated party. We retain a 30% limited partner interest in Freeport LNG.

We currently estimate that the cost of constructing the Freeport LNG facility will be approximately $650 million to $750 million, before financing costs. ConocoPhillips has agreed to provide a substantial majority of the financing to construct this facility. ConocoPhillips has also paid Freeport LNG an aggregate of $10 million in connection with the reservation of 1.0 Bcf/d of LNG regasification capacity at the terminal and $3.5 million for options up to 500 Mmcf/d of additional capacity in the event the terminal is expanded.

Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project generally are to be funded out of Freeport LNG's own cash flows and by its 60% limited partner. We have not been called upon to contribute any cash to Freeport LNG for development activities. However, we have been advised by the general partner that it plans to expand the capacity of the Freeport facility. We expect that a portion of the funding for this proposed capacity expansion will be made through capital calls upon us and the other limited partners in Freeport LNG. In the event of each such capital call, we will have the option either to contribute the requested capital or to decline to contribute. If we decline to contribute, the other limited partners could elect to make our contribution and receive back twice the amount contributed on our behalf, without interest, before any Freeport LNG cash flows are otherwise distributed to us. We currently expect to meet these capital calls using cash on hand, revenues from advance capacity reservation fees and funds raised in the future through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

Sabine Pass LNG

S-33

Chevron USA is currently negotiating with us about making a $200 million equity contribution for a 20% limited partner interest in Sabine Pass LNG. The results of such negotiations should be known by December 20, 2004, but there can be no assurance that such an agreement can be reached.

Total has paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $10 million in connection with the reservation of 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. An additional advance capacity reservation fee payment of $10 million will be payable to Sabine Pass LNG upon satisfaction of certain conditions described above. The capacity reservation fee payments will be amortized over a ten-year period as a reduction of Total's regasification capacity fee under the TUA. As a result, we intend to record the $20 million in advance payments, though non-refundable, as deferred revenue to be amortized to income over the corresponding ten-year period.

In November 2004, Chevron USA paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $5 million. Chevron USA's TUA remains subject to final corporate approval, including approval of the ChevronTexaco board of directors, by December 20, 2004. If the Chevron USA agreements and transactions are not terminated, further advance capacity reservation fee payments will be due: $7 million after ChevronTexaco's board approval; $5 million after December 20, 2004, conditioned upon both the issuance by FERC of an order authorizing construction of the Sabine Pass receiving terminal and confirmation of evidence of the ability to finance construction of the facility; and $3 million if Chevron USA exercises the option to increase its capacity at Sabine Pass to 1.0 Bcf/d. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA's regasification capacity tariff under the TUA. As a result, we intend to record the advance payments that we receive, though non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

In January 2004, we were paid $1 million by J&S Cheniere in connection with an option to purchase LNG regasification capacity in each of our Sabine Pass and Corpus Christi LNG facilities. We have recorded the option fee as deferred revenue, and it is anticipated the option fee will be recognized as revenue over the initial five-year period of the TUA contemplated by the option agreement.

Corpus Christi LNG

We currently estimate that the cost of constructing the Corpus Christi facility will be approximately $650 million to $750 million, before financing costs. The minority owner was required to fund 100% of the first $4.5 million of Corpus Christi LNG's expenditures, which amount was reached as of March 31, 2004. Since that date, we have funded 66.7% of the expenditures of Corpus Christi LNG, with the minority owner funding the balance. We currently expect to finance the construction cost of the Corpus Christi terminal in similar manner as the Sabine Pass facility. We plan to finance future capital contributions through equity or debt offerings or borrowings by Cheniere. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.

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Short-term liquidity needs

We anticipate funding our more immediate liquidity requirements, including some expenditures related to the construction of the LNG receiving terminals, through a combination of any or all of the following:

•: cash balances;
•: collection of receivables;
•: issuances of Cheniere debt and equity securities, including proceeds from this offering, and issuances of common stock pursuant to exercises by the holders of existing warrants and options;
•: LNG receiving terminal capacity reservation fees; and
•: sales of prospects generated by our exploration group.

Historical cash flows

Net cash used in operations for the nine months ended September 30, 2004 totaled $16,661,275, compared to net cash used in operations of $4,498,743 for the same period in 2003. The increase in cash used in operations was a direct result of the expansion of our LNG receiving terminal business. In the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal, but in subsequent periods, we accelerated the development schedule of our Sabine Pass and Corpus Christi LNG receiving terminals. Net cash provided by investing activities was $1,682,009 for the nine months ended September 30, 2004 as a result of the reimbursement from limited partnership investment, sales of our interests in oil and gas prospects and collection of proceeds from the sale of a limited partnership interest, partially offset by oil and gas property and fixed asset additions, LNG site costs and the purchase of the restricted certificate of deposit. Net cash provided by investing activities was $1,396,349 for the nine months ended September 30, 2003 as a result of the sale of LNG assets, a limited partnership interest and interests in oil and gas prospects, partially offset by oil and gas property and fixed asset additions. Net cash provided by financing activities was $20,847,837 for the nine months ended September 30, 2004 and $4,211,884 for the nine months ended September 30, 2003. Net cash provided by financing activities in these periods consisted primarily of private sales of common stock, exercises of warrants and stock options and partnership contributions by a minority owner, partially offset by repayments of notes payable.

At September 30, 2004, we had working capital of $6,372,798 compared to $155,526 at December 31, 2003. The increase is primarily attributable to the sale of our common stock through a private placement offering in January 2004 and exercises of warrants and stock options that resulted in aggregate net proceeds of $19,137,182. We also received a $2.5 million payment from Freeport LNG from the sale of a 60% interest in the Freeport LNG project and $2,818,898 in partnership contributions from our Corpus Christi LNG minority owner. Major uses of working capital included $17,821,846 related to LNG terminal development and other general and administrative expenses during the nine months ended September 30, 2004.

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Prior bank line of credit

On June 23, 2004, we terminated our $5 million line of credit with a commercial bank. This facility was originally established on July 25, 2003 with a borrowing base of $2 million. During 2003, we borrowed $1 million under the facility to acquire oil and gas leases. The balance was repaid in January 2004.

Restricted certificate of deposit and letter of credit

Under the terms of our office lease, we are required to post a standby letter of credit to be reduced $224,619 per annum over a five-year period. The initial letter of credit amount of $865,142, which matured on October 24, 2004, was increased to $1,123,094 in April 2004 related to the expansion of our office space. This letter of credit was initially established under the terms of our bank line of credit.

Upon the termination of our bank line of credit on June 23, 2004, we purchased a certificate of deposit in the amount of $1,123,094 and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1,123,094. Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit. As a result, the certificate of deposit plus accrued interest is classified as restricted on our balance sheet at September 30, 2004.

On October 25, 2004, both the letter of credit and certificate of deposit were amended to decrease the face amounts by $224,619 to $898,475. The renewed letter of credit matures on November 30, 2005, and the certificate of deposit matured on November 15, 2004. The certificate of deposit for $898,475 was renewed with a maturity date of April 19, 2005.

Off-balance sheet arrangements

As of September 30, 2004, we had no "off-balance sheet arrangements" that may have a current or future material affect on our consolidated financial condition or results of operations.

Lease obligation

On May 11, 2004, we amended our office lease in order to expand our existing office space. The term for the expansion space is for five years with an option, subject and subordinate to another tenant's renewal option, to renew for a term that would coincide with the term of our existing space that terminates January 2014. No rent is payable for the first nine months of the five-year term. Total payments for the remainder of the five-year expansion space lease term are $200,292 per year.

Because we are in the preliminary stage of developing our LNG receiving terminals, substantially all of the costs to date, related to such activities, have been expensed. These costs primarily include professional fees associated with front-end engineering and design work and obtaining an order from FERC authorizing construction of our terminals and other required permitting for the Sabine Pass LNG and Corpus Christi LNG receiving terminals and their related natural gas pipelines. As a result, we are incurring substantial net losses and negative operating cash flow. We anticipate that our LNG terminal construction projects will be financed

S-36

with project-level debt or equity securities, capital contributions from Cheniere and other limited partners or a combination thereof. We intend to finance our capital contributions to these projects through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

Our unaudited consolidated financial statements and notes thereto relate to the three-month and nine-month periods ended September 30, 2004 and 2003. These statements, the notes thereto and the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended, contain detailed information that should be referred to in conjunction with the following discussion.

Results of operations—comparison of the three-month periods ended September 30, 2004 and 2003

Overview

Our financial results for the three months ended September 30, 2004 reflect a net loss of $5,639,289, or $0.29 per share (basic and diluted), compared to a net loss of $2,387,021, or $0.16 per share (basic and diluted), during the corresponding period in 2003. The major factors contributing to our loss during the third quarter of 2004 were: (1) LNG receiving terminal development expenses of $3,334,982 (which were offset by a $416,831 minority interest in the operations of Corpus Christi LNG); (2) other general and administrative expenses of $1,916,300; and (3) our equity share of the net loss in Freeport LNG of $582,798.

LNG terminal development activities

LNG terminal development expenses were 42% higher in the third quarter of 2004 ($3,334,982) than in the third quarter of 2003 ($2,343,534) primarily as a result of increased LNG employee-related costs and increased development costs related to our Sabine Pass LNG receiving terminal project.

During the third quarter of 2004, we recorded $1,251,745 in terminal development expenses related to the Corpus Christi LNG terminal in which we are the general partner and own a 66.7% limited partner interest. This amount was partially offset by $416,831 related to the minority interest of our 33.3% limited partner. We also incurred $1,408,000 in direct terminal development expenses during the third quarter of 2004 related to the Sabine Pass LNG terminal, in which we own 100% of the project. In addition, in the third quarter of 2004, we incurred $677,000 (before overhead recovery of $225,000 from Corpus Christi LNG) in LNG employee-related costs. In connection with the expansion of our LNG terminal development business, our employee costs increased, as we expanded our average LNG staff from five employees during the third quarter of 2003 to 16 employees during the third quarter of 2004.

During the third quarter of 2003, we incurred $2,343,534 in LNG receiving terminal development expenses. Of this amount, $1,132,211 related to development costs for the Corpus Christi LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner, which provided 100% of the funding for the first $4.5 million of partnership expenditures. Because partnership expenditures had reached $4.5 million as of March 31, 2004, the minority owner began sharing in all subsequent expenditures based on its

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33.3% limited partner interest. Also during the third quarter of 2003, we incurred $1,196,000 primarily for development expenses related to the Sabine Pass LNG project.

During the third quarter of 2004, our 30% equity share of the loss from Freeport LNG was $582,798 compared to our equity share of the loss of $595,688 for the third quarter of 2003.

Non-cash compensation

Non-cash compensation during the third quarter of 2004 is related to restricted stock awards issued in February 2004 to employees and non-employee directors based on our performance in 2003. The value of these restricted shares was recorded as a reduction to stockholders' equity as deferred compensation to be amortized over two years as vesting occurs. The $438,542 of non-cash compensation (net of $40,208 capitalized as oil and gas property costs) recorded in the third quarter of 2004 is entirely related to the amortization of such deferred compensation.

Other general and administrative expenses

Other general and administrative, or G&A, expenses are primarily related to our general corporate and other activities. These expenses increased $1,301,046, or 211%, to $1,916,300 in the third quarter of 2004 compared to $615,254 in the corresponding quarter in 2003. G&A expenses increased primarily because of the expansion of our business (including increases in our average corporate staff from five employees during the third quarter of 2003 to 15 employees during the third quarter of 2004) and increased professional and other fees primarily in connection with securities compliance filings and increased securities registrations. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $197,005 (in addition to the $40,208 related to non-cash compensation mentioned earlier) in the third quarter of 2004 compared to $248,000 during the comparable period in 2003.

Depreciation, depletion and amortization expenses

Depreciation, depletion and amortization, or DD&A, expenses increased $164,598, or 163%, to $265,601 in the third quarter of 2004 from $101,003 in the third quarter of 2003. The increase is primarily related to increased oil and gas DD&A expenses as a result of increased production volumes discussed below and higher depreciation related to increased furniture, fixtures and equipment associated with the expansion of our business.

Oil and gas activities

Oil and gas revenues increased by $330,004, or 244%, to $465,249 in the third quarter of 2004 from $135,245 in the third quarter of 2003 as a result of a 201% increase in production volumes (80,488 thousand cubic feet of Mcfe, in the third quarter of 2004 compared with 26,725 Mcfe in the third quarter of 2003) and a 13% increase in average natural gas prices to $5.73 per Mcf, in the third quarter of 2004 from $5.06 per Mcf in the third quarter of 2003. We produced from an average of 10 wells in the third quarter of 2004 compared to an average of seven wells in the third quarter of 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests. The small amount of production taxes in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

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Results of operations—comparison of the nine-month periods ended September 30, 2004 and 2003

Overview

Our financial results for the nine months ended September 30, 2004 reflect a net loss of $14,767,155, or $0.79 per share (basic and diluted), compared to a net loss of $889,954, or $0.06 per share (basic and diluted), during the corresponding period in 2003.

The major factors contributing to our net loss during the first nine months of 2004 were: (1) LNG receiving terminal development expenses of $12,664,635 (which were offset by a $2,650,210 minority interest in the operations of Corpus Christi LNG); (2) non-cash compensation of $2,699,375 related to 2004 stock awards to employees and non-employee directors based on our performance in 2003; and (3) other general and administrative expenses of $5,157,211. These factors were partially offset by a $2.5 million reimbursement from our limited partnership investment in Freeport LNG.

LNG terminal development activities

LNG terminal development expenses were 277% higher in the first nine months of 2004 ($12,664,635) than in the first nine months of 2003 ($3,360,643). These expenses were significantly higher because we accelerated, beginning in the third quarter of 2003, the schedule of terminal development for our Sabine Pass and Corpus Christi LNG receiving terminals.

During the first nine months of 2004, we recorded $5,135,293 in terminal development expenses related to the Corpus Christi LNG terminal. This amount was partially offset by $2,650,210 related to the minority interest of our 33.3% limited partner. Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4.5 million of project expenditures. As project expenditures had reached $4.5 million by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest. Also during the first nine months of 2004, we incurred $5,617,000 in direct terminal development expenses related to our Sabine Pass LNG terminal, in which we own 100% of the project. In addition, during the first nine months of 2004, we incurred $2,064,000 (before overhead recovery of $675,000 from Corpus Christi LNG) in LNG employee-related costs. In connection with the expansion of our LNG business, our employee costs increased, as we expanded our average LNG staff from four employees during the first nine months of 2003 to 14 employees during the first nine months of 2004.

During the first nine months of 2003, we incurred $3,360,643 in LNG receiving terminal development expenses. Of this amount, $1,552,978 related to development costs for the Corpus Christi LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner as discussed above. Also during the first nine months of 2003, we incurred $1,624,000 primarily for development expenses related to the Sabine Pass LNG project.

In February 2003, our Freeport LNG terminal project was acquired by Freeport LNG in which we received a 40% limited partnership interest and payments to us totaling $5 million over time. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4,760,000. We also sold a 10% interest in Freeport LNG in March 2003 for $2,333,333, resulting in a gain

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of $423,454. During 2003, we received payments totaling $2.5 million from Freeport LNG, which were recorded as a reduction to our investment in the partnership. In addition, during 2003 we recorded equity in the 2003 loss incurred by Freeport LNG attributable to our 30% limited partner interest, which reduced our investment basis to zero as of December 31, 2003. In January 2004, we received the final $2.5 million payment from Freeport LNG. Because our investment basis in Freeport LNG had been reduced to zero, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations for the nine months ended September 30, 2004.

During the first nine months of 2004, our 30% equity share of net income from Freeport LNG was $84,473, after deducting $278,071 of loss that was not recorded as of December 31, 2003. This compares to our equity share of the loss of $2,655,635 for the first nine months of 2003. The significant improvement from a loss to net income between periods for Freeport LNG was a result of Freeport LNG's receipt of a non-refundable capacity reservation fee of $10 million from ConocoPhillips in January 2004, upon the delivery of specific engineering and design studies.

Non-cash compensation

Non-cash compensation of $2,699,375 (net of $492,292 capitalized as oil and gas property costs) incurred during the first nine months of 2004 resulted from bonus and restricted stock awards issued in February 2004 to employees and non-employee directors based on our performance in 2003. We expensed non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share, which shares were fully vested on the date of grant. In addition, we have recorded non-cash compensation related to eight months amortization of restricted stock awards previously recorded as deferred compensation and amortizable over two years as vesting occurs.

Other general and administrative expenses

Other G&A expenses primarily relate to our general corporate and other activities. These expenses increased $3,429,156, or 198%, to $5,157,211 in the first nine months of 2004 compared to $1,728,055 in the first nine months of 2003. The increase in G&A expenses resulted primarily from the expansion of our business (including increases in average corporate staff from five employees during the first nine months of 2003 to 14 employees during the first nine months of 2004) and increased professional and other fees incurred in connection with securities compliance filings and securities registrations. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $720,908 (in addition to the $492,292 related to non-cash compensation mentioned earlier) in the first nine months of 2004 compared to $728,000 during the comparable period in 2003.

Depreciation, depletion and amortization expenses

DD&A expenses increased $380,950, or 152%, to $631,956 in the first nine months of 2004 from $251,006 in the first nine months of 2003. The increase primarily resulted from higher oil and gas DD&A expenses as a result of greater production volumes discussed below and also from more depreciation expense resulting from the acquisition of furniture, fixtures and equipment associated with the expansion of our business.

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Oil and gas activities

Oil and gas revenues increased by $765,575, or 209%, to $1,132,240 in the first nine months of 2004 from $366,665 in the first nine months of 2003 as a result of a 195% increase in production volumes (194,328 Mcfe in the first nine months of 2004 compared with 65,900 Mcfe in the first nine months of 2003) and a 4% increase in average natural gas prices to $5.82 per Mcf in the first nine months of 2004 from $5.57 per Mcf in the first nine months of 2003. We produced from an average of 10 wells in the first nine months of 2004 as compared with an average of six wells in the first nine months of 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests. The small amount of production taxes in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

Other matters

New accounting pronouncements

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, and subsequently revised the Interpretation in December 2003 (FIN 46R). This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities, which have certain characteristics. As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004. We adopted FIN 46R effective January 1, 2004, with no material effect on our consolidated financial statements.

Other recent developments

In July 2003, an issue was brought before the FASB regarding whether or not contract-based oil and gas mineral rights held by lease or contract, or mineral rights, should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets as defined in Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No. 142, "Goodwill and Other Intangible Assets," became effective for transactions subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies.

In September 2004, the FASB issued final FASB Staff Position (FSP) FAS 142-2, "Application of SFAS No.142 to Oil and Gas Producing Entities." The FSP clarifies that the exception in paragraph 8(b) of SFAS No. 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the exception extends to the disclosure provisions of SFAS No. 142 for drilling and mineral rights of oil and gas producing entities.

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Business

LNG industry

Business strategy and competitive strengths

Our goal is to continue to increase shareholder value by pursuing a strategy with the following primary components:

•: complete the development and construction of our onshore U.S. Gulf Coast LNG receiving terminals;
•: secure "anchor tenants" under long-term TUAs for approximately two-thirds of existing and future regasification capacity at the LNG terminals that we control, and retain the remaining capacity for our own account to capitalize on future long-term, short-term or spot market opportunities;
•: apply proven, conventional technology to mitigate development and operating risk and facilitate permitting, while utilizing the latest control and safety technology;
•: grow our terminal business by expanding our existing projects and pursue the development of additional LNG receiving terminals on the U.S. Gulf Coast and elsewhere; and
•: evaluate the use of our receiving terminal assets to pursue upstream opportunities, such as investing in LNG shipping businesses or development of natural gas reserves that

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could be converted into LNG, as well as downstream opportunities, such as investing in natural gas pipelines and storage.

We believe that we hold several competitive advantages, which drive this strategy and enhance our efforts to increase shareholder value:

U.S. Gulf Coast Focus. The U.S. Gulf Coast area is conducive to LNG receiving terminal development, as it is distinguished by substantial local consumption coupled with extensive natural gas pipeline infrastructure. According to the EIA, natural gas consumption in Texas and Louisiana in 2003 totaled approximately 12.7 Bcf/d and pipeline capacity from the U.S. Gulf Coast in 2001 totaled approximately 19 Bcf/d. Capacity is currently available on major natural gas pipelines in the vicinity of each of our sites and, with declining U.S. Gulf Coast natural gas production, we believe that more of the existing pipeline infrastructure will become available for transporting natural gas imported as LNG.

Environmental and Community Friendly Approach. We are committed to an environmentally sound and community friendly approach in developing our LNG receiving terminals. At each potential site, we invest time to develop strong community relationships. We begin the application process for a facility only after we are convinced that the local community understands the process and is willing to support our project. Furthermore, the local governments in Texas and Louisiana are familiar with and supportive of the energy industry. We have received written letters in support of the development of our Sabine Pass LNG receiving terminal from Louisiana state representatives, a U.S. Senator from Louisiana, the Governor of Louisiana and local organizations. We have received written letters in support of the development of our Corpus Christi LNG receiving terminal from the Governor of Texas, the Mayor of Corpus Christi, the Sierra Club and local organizations. In addition, FERC has held public hearings with respect to the development of our proposed Sabine Pass and Corpus Christi LNG receiving terminals, at which the local communities expressed support of our facilities.

Experienced Management Team with Significant Shareholdings. To pursue this business, we have assembled a team of professionals with extensive experience in the LNG industry. Through

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tenure with major oil companies, major operators of LNG receiving terminals and major engineering and construction companies, our senior management team has an average of more than 20 years of experience in the areas of LNG project development, operation, engineering, technology, transportation and marketing. Furthermore, our officers, directors and employees will beneficially own approximately 17% of our shares outstanding after this offering. We believe that such ownership provides appropriate incentive for our employees to increase shareholder value and serves to align their interests with those of our shareholders.

Our LNG receiving terminals

We began developing our LNG receiving terminal business in 1999 and, since then, have been among the first companies to secure sites and commence development of new LNG receiving terminals in the United States. We have focused our initial development efforts on three LNG receiving terminal projects, located near Freeport, Texas, in Cameron Parish, Louisiana near Sabine Pass, and near Corpus Christi, Texas. For certain statistical data related to these three proposed facilities, see the table set forth in the "Executive summary" on page S-3.

Freeport LNG

Development

We initiated development of the LNG receiving facility on Quintana Island near Freeport, Texas. In February 2003, we consummated a transaction with entities controlled by Michael S. Smith, or the Smith entities, to contribute to Freeport LNG all of the interest in the Freeport site and project that we acquired in June 2001 in exchange for a 40% limited partner interest in Freeport LNG and $9.1 million of cash payments, all of which has been received. Smith entities owned the general partner interest and the remaining 60% limited partner interest. Smith entities committed to contribute up to $9 million to fund Freeport LNG's development costs and to apply available proceeds from any sales of options, capacity reservations and loans related to capacity reservations to these costs. In addition, Freeport LNG assumed our obligation to pay to the seller of the lease option for the Freeport site a royalty of $0.03 per Mcf on the quantities of gas processed through the Freeport LNG terminal, subject to a maximum royalty of approximately $11 million per year. In March 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG.

The Freeport LNG receiving terminal is being developed on a 233-acre tract of land and is designed with regasification capacity of 1.5 Bcf/d, one dock and two LNG storage tanks with an aggregate LNG storage capacity of 6.7 Bcfe. The unloading dock will be able to handle 78,000 cm to 200,000 cm LNG tankers. Based on discussions with Freeport LNG, we believe the estimated cost to construct the facility is approximately $650 million to $750 million, before financing costs. We believe that this cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices.

In June 2004, FERC issued an order authorizing Freeport to construct and operate the LNG receiving terminal, subject to specified conditions that must be satisfied prior to commencement of construction; other necessary federal, state and local approvals are anticipated to be obtained by the end of 2004. The front-end engineering and design study for the Freeport LNG project was completed in January 2004. We anticipate that construction will

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begin in the first quarter of 2005, and terminal operations will commence in late 2007 at the earliest. We expect that Freeport LNG will have increases in expenses and debt and increases in contributed capital from other partners as it proceeds with planning, development and construction of the Freeport LNG receiving terminal.

Dow TUA

On March 1, 2004, Freeport LNG and Dow entered into a 20-year TUA. Under the TUA between Freeport LNG and Dow, Freeport LNG is obligated to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. In August 2004, Dow exercised its option under the TUA to double the amount of its initial regasification capacity reserved of 250 Mmcf/d. In addition, Freeport LNG will provide for the transportation and delivery of natural gas in the facility's 9.4 mile pipeline to Stratton Ridge, Texas for interconnection with downstream pipelines. Freeport LNG has no obligation to provide certain services such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats, and (ii) the construction of facilities, or the transportation of natural gas, downstream from the LNG terminal.

Including its option exercise, Dow has reserved 195,275,000 Mmbtu of annual regasification capacity under the TUA, which is equivalent to approximately 500 Mmcf/d of capacity, assuming an energy content of 1.07 Mmbtu per Mcf. The Dow TUA commences between April 2007 and March 2008, runs for an initial term of 20 years from the date on which services commence for Dow at the Freeport LNG facility and is subject to three additional 10-year extensions. Dow is required to pay Freeport LNG a monthly reservation fee for this regasification capacity. In addition, each month Freeport LNG is entitled to retain a percentage of Dow's share of LNG to be used as fuel at the facility. Dow is also required to pay a portion of power and other operating costs.

Freeport LNG and Dow are liable for certain delays and nonperformance under force majeure circumstances. In addition, Freeport LNG is obligated to pay liquidated damages in the event of certain types of docking and unloading delays.

Each of Freeport LNG and Dow may assign or pledge its interests under the TUA in connection with the construction and term financing of the proposed Freeport LNG receiving terminal. In addition, Dow may assign all or a portion (each, limited by quantity and duration) of its right to use the available services to (i) an affiliate upon notice to, but without the consent of, Freeport LNG or (ii) any other person upon the written consent of Freeport LNG, which consent is not to be unreasonably withheld, provided that the assignee executes a TUA with Freeport LNG and Dow agrees to modifications to the gas redelivery and quantity provisions of the Dow TUA to reflect such assignment.

Dow may terminate the TUA during the construction period if Dow reasonably determines that substantial completion of the Freeport LNG terminal (so that it is ready to be used for its intended purpose) will not occur by a future confidential date, provided that Freeport LNG does not cure the situation within 30 days following notice thereof. Each of Dow and Freeport LNG may terminate the TUA if (i) Freeport LNG does not obtain, by December 31, 2004, all approvals necessary to construct and operate the Freeport LNG receiving terminal or (ii) Freeport has not provided to Dow evidence that it has successfully arranged and closed on financing of the Freeport LNG receiving terminal by June 30, 2005.

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ConocoPhillips TUA

ConocoPhillips has paid nonrefundable capacity reservation fees of $13.5 million during 2004, has reserved 1.0 Bcf/d of regasification capacity in the terminal, has purchased options to reserve up to 500 Mmcf/d of additional regasification capacity in the event the terminal is expanded, has acquired a 50% interest in the general partner of Freeport LNG and has agreed to provide a substantial majority of the construction funding. ConocoPhillips will be primarily responsible for managing the construction and operation of the facility.

On July 2, 2004, ConocoPhillips and Freeport LNG entered into a long-term TUA. Under the TUA between Freeport LNG and ConocoPhillips, Freeport LNG is obligated to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. In addition, Freeport LNG will provide for the transportation and delivery of natural gas in the facility's 9.4 mile pipeline to Stratton Ridge, Texas for interconnection with downstream pipelines. Freeport LNG has no obligation to provide certain services to ConocoPhillips such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats and (ii) the transportation of natural gas downstream from the LNG terminal or the construction of any pipelines to provide such transportation.

ConocoPhillips has reserved 390,550,000 Mmbtu of annual regasification capacity under the TUA, which is equivalent to approximately 1.0 Bcf/d of capacity, assuming an energy content of 1.07 Mmbtu per Mcf. The ConocoPhillips TUA commences between April 2007 and March 2008, runs for an initial term until February 2033 and is subject to six additional 10-year extensions. ConocoPhillips is required to pay Freeport LNG a monthly reservation fee for this regasification capacity. However, up to $0.05 per Mmbtu is subject to reduction for any calculated annual shortfalls in available capacity, which are reconciled on both a monthly and an annual basis. In addition, each month Freeport LNG is entitled to retain ConocoPhillips' allocable share of LNG used as fuel at the facility and which is subject to unavoidable losses. ConocoPhillips is also required to pay on a monthly basis a portion of power and other operating costs.

Freeport LNG and ConocoPhillips are liable for certain delays and nonperformance under force majeure. In addition, Freeport LNG is obligated to pay liquidated damages in the event of certain types of docking and unloading delays.

Both Freeport LNG and ConocoPhillips may assign their interests under the TUA to affiliates. In addition, Freeport LNG may pledge its interest under the TUA to lenders to secure indebtedness incurred to finance the construction and term financing of the proposed facility. In addition, ConocoPhillips may make a partial assignment of its total reserved regasification capacity to nonaffiliates upon the written consent of Freeport LNG, which consent is not to be unreasonably withheld. Any such partial assignee would be required to enter into a TUA with Freeport LNG with appropriate modifications to the quantity provisions but otherwise with substantially the same terms as the TUA between Freeport LNG and ConocoPhillips. An assignment will not end the obligations of ConocoPhillips under the TUA unless the assignee agrees to be bound by the provisions of the TUA and, in the case of ConocoPhillips, its assignee demonstrates, including through a parent guarantee or irrevocable letter of credit, that it has a creditworthiness that is the same or better than that of ConocoPhillips.

ConocoPhillips may terminate the TUA during the construction period if ConocoPhillips reasonably determines that the conversion date (as defined in the credit agreement between

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Freeport LNG and ConocoPhillips) will not occur by a future confidential date, subject to a 30-day cure period on the part of Freeport LNG.

Funding

Freeport LNG has entered into a credit agreement with ConocoPhillips for ConocoPhillips to provide a substantial majority of the debt financing for the project. In the event the funding provided by ConocoPhillips is insufficient to meet the capital expenditures or working capital requirements of Freeport LNG, the general partner of Freeport LNG may obtain such additional funding from any of the following sources:

•: cash reserves of Freeport LNG;
•: loans from banks and other non-affiliate independent sources;
•: additional capital contributions made to Freeport LNG by the partners;
•: loans made to Freeport LNG by the partners or their affiliates; or
•: any other funding source determined by the general partner of Freeport LNG.

The general partner of Freeport LNG is authorized to do all things necessary to obtain debt and equity financing in connection with any expansion of the facility. Any equity financing obtained for such expansion will dilute the ownership interests of the limited partners on a pro rata basis. However, we and the other limited partners have preemptive rights that allow any limited partner to maintain its percentage ownership interest in Freeport LNG.

Our expectations regarding Freeport LNG

We account for our ownership in Freeport LNG under the equity method. We estimate that we would receive pre-tax cash distributions with respect to our interest in Freeport LNG ranging from approximately $10 million to $20 million per year, based on the following assumptions: (i) that our ownership interest remains at 30%, (ii) construction occurs on schedule at expected project and financing costs, (iii) operating costs fall within expected ranges and (iv) the Dow and ConocoPhillips TUAs remain in effect in their current forms. These expectations involve assumptions, risks and uncertainties beyond our control, and these expectations may prove to be incorrect.

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Pipeline

As part of the terminal operations, natural gas will be transported through a 9.4-mile, 36-inch diameter pipeline to the delivery point at Stratton Ridge, Texas, which is a major point of interconnection with the Texas intrastate gas pipeline grid.

Sabine Pass LNG

Development

We are developing an LNG receiving terminal in Cameron Parish, Louisiana, near Sabine Pass. We formed Sabine Pass LNG, to develop the terminal. We have options on three tracts of land comprising 568 acres in Cameron Parish, Louisiana for the project site.

The LNG receiving terminal will be designed with an anticipated regasification capacity of 2.6 Bcf/d, two docks and three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcfe. Subject to obtaining financing and an additional order by FERC authorizing construction of an expansion at our Sabine Pass LNG receiving terminal, the facility near Sabine Pass could be expanded from its initial capacity of 2.6 Bcf/d to approximately 3.0 to 4.0 Bcf/d.

The facility will have two unloading docks that can handle 87,000 cm to 250,000 cm LNG shipping vessels. The cost to construct the Sabine Pass LNG facility is currently estimated at approximately $750 million to $850 million, before financing costs. This estimate is based in part on our ongoing negotiations regarding a lump-sum turnkey contract with a major international EPC contractor. Our cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices (particularly steel).

On December 22, 2003, we submitted to FERC an application for an order authorizing us to construct the LNG receiving facility near Sabine Pass, as well as a separate but concurrent application for its related pipeline. On November 12, 2004, FERC issued the FEIS for our proposed Sabine Pass LNG receiving terminal and the related pipeline. In the FEIS, FERC concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that, in December 2004, FERC will issue an order authorizing construction of this terminal, subject to specified conditions that must be satisfied prior to commencement of construction. Construction is anticipated to begin in the first quarter of 2005, and terminal operations are anticipated to commence in 2008. Because of the soil conditions at our proposed Sabine Pass LNG receiving terminal, the construction process will begin with soil testing and site preparation. The front-end engineering design work for the Sabine Pass terminal was completed by Black & Veatch Pritchard, Inc.

Total TUA

On September 2, 2004, Sabine Pass LNG entered into a TUA with Total to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. Sabine Pass LNG has no obligation to provide Total with certain services such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats, (ii) the transportation of natural gas downstream from the LNG terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

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Under the TUA, Total has reserved 390,915,000 Mmbtu of annual regasification capacity, which is equivalent to approximately 1 Bcf/d of capacity, assuming an energy content of 1.05 Mmbtu per Mcf. The Total TUA is scheduled to commence no later than April 2009, runs for an initial term of 20 years and is subject to six additional 10-year extensions. Total has agreed to pay a monthly fixed capacity reservation fee of $9,121,350; and a monthly operating fee of $1,303,050, which is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers). After the Total TUA commences, the sum of these payments would be approximately $125 million per year before inflation. This calculation assumes that the Total TUA remains in effect in its current form. These monthly payment amounts are equivalent to payments of $0.28 per Mmbtu for capacity and $0.04 per Mmbtu for operating fees, respectively, of reserved monthly regasification capacity. In addition, each month Sabine Pass LNG is entitled to retain 2% of the LNG delivered for Total's account for use as fuel at the facility. Total's obligations under the TUA are supported by an irrevocable guarantee in favor of Sabine Pass LNG by Total S.A.

If any governmental authority (i) imposes any taxes on Sabine Pass LNG (excluding taxes on revenue or income) with respect to the services provided under the TUA, or the proposed LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases the costs of Sabine Pass LNG in relation to the services provided or the proposed LNG receiving terminal, Total will bear such taxes or increased regulatory costs at the rate of 40%, subject to adjustment if the total LNG regasification facilities are expanded. To the extent any ad valorem taxes are imposed and not abated, we will reimburse Total for up to one-half of such amount not to exceed $3,909,000 per year.

Sabine Pass LNG is obligated to pay liquidated damages to Total in the event of certain types of docking and unloading delays.

Both Sabine Pass LNG and Total may assign their interests under the TUA to affiliates, and Sabine Pass LNG may pledge its interest under the TUA to lenders to secure indebtedness incurred to finance the construction and term financing of the proposed LNG receiving terminal. In addition, Total may make a partial assignment of its total reserved regasification capacity to nonaffiliates provided that (i) the assignee agrees to be bound by the TUA, (ii) the parent guarantee continues to apply to all assigned obligations and (iii) Total and the assignee designate a representative and jointly exercise all rights under the TUA.

Total may terminate the TUA if:

•

Sabine Pass LNG has declared force majeure with respect to a period that has extended, or is projected to extend, for 18 months; or

•

for reasons not excused by force majeure or Total's actions, if Sabine Pass LNG:

•: failed to deliver at least 191,625,000 Mmbtu of Total's total natural gas nominations in a 12-month period;
•: failed entirely to receive at least 15 cargoes nominated by Total over a period of 90 consecutive days;
•: failed to unload 50 cargoes or more scheduled for delivery by Total for a 12-month period; or

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•: allowed for a period exceeding 15 days, either (i) the debt-to-equity ratio of Sabine Pass LNG to exceed 80/20 or (ii) if Sabine Pass LNG has obtained a credit rating by Moody Investor Service, Standard and Poor's or Fitch Ratings, two of its credit ratings fall below a "B2" by Moody's, a "B" by S&P or a "B" by Fitch and the debt-to-equity ratio of Sabine Pass LNG on such 15^th day exceeds 80/20.

Sabine Pass LNG may terminate the TUA if:

•: the parent guarantee ceases to be in full force and effect;
•: for a period exceeding 15 days, two of the parent guarantor's credit ratings fall below investment grade; or
•: the parent guarantor commences bankruptcy or liquidation proceedings, or has such proceedings commenced against it.

Either party may terminate the TUA with 30 days written notice (i) if a party has failed to pay when due an amount owed that causes its cumulative delinquency to exceed three times the monthly capacity reservation fee, (ii) the other party has given 30 days written notice of the cumulative delinquency and (iii) the cumulative delinquency has not been paid within 60 days of such notice.

In November 2004, Total exercised its option to proceed with the transaction by delivering to Sabine Pass LNG an advance capacity reservation fee payment of $10 million and a guarantee by its parent entity, Total S.A., of certain Total obligations under the TUA. Cheniere, Sabine Pass LNG and Total also entered into an omnibus agreement on September 2, 2004, under which the TUA remains subject to certain conditions. Under the omnibus agreement, if Sabine Pass LNG enters into a new TUA with a third party, other than our affiliates, for capacity of 50 Mmcf/d or more, with a term of five years or more, prior to the commercial start date of the terminal, Total will have the option, exercisable within 30 days of the receipt of notice of such transaction, to adopt the pricing terms contained in such new TUA for the remainder of the term of the Total TUA.

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10 million will be payable to Sabine Pass LNG upon satisfaction of the following conditions under the Total omnibus agreement: (i) approval by FERC of the pending application to build the Sabine Pass LNG receiving terminal and (ii) evidence of the ability to finance construction of the facility, which will be deemed satisfied if Sabine Pass LNG has entered into a loan agreement with a creditworthy lender with sufficient equity to be contributed to finance the facility and an acceptable EPC contractor has accepted the notice to proceed with construction. Total has the right to terminate this transaction under the omnibus agreement if these conditions are not satisfied by June 30, 2005.

Chevron USA TUA

On November 8, 2004, Sabine Pass LNG entered into a TUA with Chevron USA, pursuant to which Sabine Pass LNG is obligated to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. Sabine Pass LNG has no obligation to provide certain services such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats, (ii) the transportation of natural gas downstream

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from the LNG terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

Under the TUA, Chevron USA has reserved 282,761,850 Mmbtu of annual regasification capacity, which is equivalent to approximately 700 Mmcf/d of capacity, assuming an energy content of 1.085 Mmbtu per Mcf. The Chevron USA TUA commences between February 2009 and July 2009, runs for an initial term of 20 years and is subject to two additional 10-year extensions. Chevron USA is required to pay Sabine Pass LNG a monthly fee for this regasification capacity that is comprised of (i) a reservation fee of $0.28 per Mmbtu of one-twelfth of the reserved annual regasification capacity and (ii) an operating fee of $0.04 per Mmbtu of one-twelfth of the reserved annual regasification capacity. After the Chevron USA TUA commences, the sum of these payments would be approximately $90 million per year before inflation. This calculation assumes that the Chevron USA TUA remains in effect in its current form. The operating fee is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers). In addition, each month Sabine Pass LNG is entitled to retain 2% of the LNG delivered for Chevron USA's account for use as fuel at the facility. ChevronTexaco Corporation will be required to guarantee 80% of Chevron USA's payment obligations under the TUA.

If any governmental authority (i) imposes any taxes on Sabine Pass LNG (excluding taxes on revenue or income) with respect to the services provided under the TUA, or the proposed LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases the costs of Sabine Pass LNG in relation to the services provided or the proposed LNG receiving terminal, Chevron USA will bear a proportionate share of such taxes or increased regulatory costs equal to 28%, subject to adjustment if Chevron USA exercises its capacity options.

Sabine Pass LNG is obligated to pay liquidated damages to Chevron USA in the event of certain types of docking and unloading delays.

Both Sabine Pass LNG and Chevron USA may assign their interests under the TUA to affiliates, and Sabine Pass LNG may pledge its interest under the TUA to lenders to secure indebtedness incurred to finance the construction and term financing of the proposed LNG receiving terminal. In addition, Chevron USA may make a partial assignment of its total reserved regasification capacity to nonaffiliates provided (i) the assignee agrees to bound by the TUA, (ii) the parent guarantee continues to apply to all assigned obligations, (iii) Chevron USA remains liable for payments owed and (iv) the respective responsibilities of the parties under the TUA are not increased or decreased.

An assignment under the TUA will terminate Chevron USA's obligations only if (i) the assignment constitutes all of such party's rights and obligations under the TUA, (ii) the assignee agrees to be bound by the TUA and (iii) the assignee demonstrates creditworthiness at the time of the assignment that is the same or better than the guarantor, in the case of Chevron USA, or Sabine Pass LNG, in its case.

Chevron USA may terminate the TUA if:

•: Sabine Pass LNG has declared force majeure with respect to a period that has extended, or is projected to extend, for 18 months; or

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•

for reasons not excused by force majeure or Chevron USA's actions, if Sabine Pass LNG:

•: failed to deliver at least 141,380,925 Mmbtu of Chevron USA's total natural gas nominations in a 12-month period;
•: failed entirely to receive 12 cargoes or more nominated by Chevron USA over a period of 90 days; or
•: failed to unload, or notified Chevron USA that it would be unable to unload, 37 cargoes or more scheduled for delivery by Chevron USA for a 12-month period.

Sabine Pass LNG may terminate the TUA if the parent guarantee ceases to be in full force and effect or if the parent guarantor or Chevron USA commences bankruptcy, insolvency or liquidation proceedings, or has such proceedings commenced against it, that are not stayed within 60 days.

Cheniere, Sabine Pass LNG and Chevron USA simultaneously entered into an omnibus agreement, under which Chevron USA agreed to make advance capacity reservation fee payments and the companies agreed to continue to negotiate with Chevron USA about making a $200 million equity investment to acquire a 20% limited partner interest in Sabine Pass LNG. The TUA and omnibus agreement remain subject to final corporate approvals, including approval by the ChevronTexaco's board of directors, by December 20, 2004. Under the omnibus agreement, Chevron USA has the option, at the same fee, either to reduce its reserved capacity at the Sabine Pass LNG facility to 500 Mmcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005, which before inflation would result in annual gross payments after the Chevron USA TUA commences of approximately $65 million (for 500 Mmcf/d) or $129 million (for 1 Bcf/d), respectively. This calculation assumes that the Chevron USA TUA remains in effect in its current form. ChevronTexaco Corporation will guarantee certain Chevron USA obligations under the TUA.

The omnibus agreement requires Chevron USA to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, beginning with a non-refundable payment of $5 million, which was received in November 2004. Except for this $5 million payment, Chevron USA has the right to terminate the TUA, the omnibus agreement and the transactions under those agreements if final corporate approvals, including approval by ChevronTexaco's board of directors, are not obtained by December 20, 2004. If the agreements and transactions are not terminated, further advance capacity reservation fee payments will be due. A payment of $7 million will be due after ChevronTexaco's board approval. A payment of $5 million will be due after December 20, 2004 upon satisfaction of the following conditions: (i) issuance by FERC of an order authorizing construction of the Sabine Pass LNG receiving terminal; and (ii) confirmation of evidence of the ability to finance construction of the facility (which will be deemed confirmed if the EPC construction company accepts the notice to proceed under the EPC contract). A payment of $3 million will be due if Chevron USA exercises the option to increase its reserved capacity at the Sabine Pass LNG facility to 1.0 Bcf/d.

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Funding

Pipeline

We have submitted to FERC an application to construct a 16-mile, 42-inch diameter natural gas pipeline designed to transport 2.6 Bcf/d of regasified LNG from the Sabine Pass LNG facility, running easterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas pipelines in southwest Louisiana, including pipelines operated by Natural Gas Pipeline Company of America, Transcontinental Gas Pipeline Corporation and Louisiana Resources Pipeline Company. We believe these existing pipelines are currently capable of transporting approximately 3.8 Bcf/d. It is also possible that one or more other pipeline operators will undertake to build pipeline connections to the Sabine Pass LNG facility. We expect that constructing these pipeline connections will require far less capital and time than the construction of our Sabine Pass LNG facility. Notwithstanding the completion of the foregoing permitting work, we are under no obligation to provide pipeline arrangements from the terminals to downstream locations. Our ultimate decisions regarding pipeline connection to the facility will depend upon future developments, including, in particular, customer interest and general market demand for natural gas from the terminal.

Corpus Christi LNG

Development

We are also developing an LNG receiving terminal near Corpus Christi, Texas. We formed Corpus Christi LNG, L.P., or Corpus Christi LNG, in May 2003 to develop the terminal. We contributed our technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus Christi LNG. A third party, BPU LNG, committed to contribute its approximately 210-acre tract of land, plus related easements and additional rights, to an additional 400 acres, and cash to fund the first $4.5 million of Corpus Christi LNG project expenses, in exchange for its 33.3% limited partner interest. In January 2004, BPU LNG entered into an option agreement with Corpus Christi LNG to acquire 100 Mmcf/d of regasification capacity at the terminal. We will manage the project through the sole general partner interest in Corpus Christi LNG held by our wholly-owned subsidiary.

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The Corpus Christi LNG receiving terminal is anticipated to be designed with regasification capacity of 2.6 Bcf/d, two docks and three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcfe. Subject to obtaining financing and an additional order by FERC authorizing construction of an expansion at our Corpus Christi LNG receiving terminal, the facility near Corpus Christi could be expanded from its initial capacity of 2.6 Bcf/d to approximately 3.0 to 4.0 Bcf/d.

The facility will have two unloading docks, which can handle 87,000 cm to 250,000 cm LNG shipping vessels. The cost to construct the Corpus Christi facility is currently estimated at approximately $650 million to $750 million, before financing costs. This estimate is based in part on our negotiations regarding a lump-sum turnkey contract with a major international EPC contractor. Our cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices (particularly steel). The minority owner was required to fund 100% of the first $4.5 million of Corpus Christi LNG's expenditures, which amount was reached as of March 31, 2004. Since that date, we have funded 66.7% of the expenditures of Corpus Christi LNG, with the minority owner funding the balance.

On December 22, 2003, we submitted to FERC an application for a permit to build the Corpus Christi LNG receiving terminal, as well as a separate but concurrent permit application for its related pipeline. On November 18, 2004, FERC issued the DEIS for our proposed Corpus Christi LNG receiving terminal and our related pipeline. In the DEIS, FERC preliminarily concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that we will receive, by the second quarter of 2005, an order by FERC authorizing construction of this terminal, subject to specified conditions that must be satisfied prior to commencement of construction. We expect to begin construction in the third quarter of 2005 and to commence terminal operations in 2009. The front-end engineering design work for the Corpus Christi terminal was completed by Black & Veatch Pritchard, Inc. We expect to engage a major international EPC contractor to perform the EPC work for the facility under a lump-sum, turnkey contract.

Customers

Implementing the strategy we used for Sabine Pass LNG, we have provided detailed information and engaged in preliminary discussions with potential customers in an effort to secure long-term TUAs for our Corpus Christi terminal. Corpus Christi LNG has not yet entered into any TUAs. We are marketing 1.5 Bcf/d of capacity under long-term TUAs at $0.32 per Mmbtu, the same price contracted for at Sabine Pass LNG. However, we cannot assure you that we will be able to obtain any TUAs for Corpus Christi on terms acceptable to us at that price, or at all.

Funding

We estimate that the cost of constructing the 2.6 Bcf/d Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs. This estimate is based in part on our negotiations regarding a lump-sum turnkey contract with a major international EPC contractor. Our cost estimate is subject to change due to contingencies such as cost overruns, change orders and changes in commodity prices (particularly steel). We currently plan to obtain funding for the facility using a project financing structure similar to the financing model we are using for Sabine Pass LNG.

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Pipeline

We have submitted to FERC an application to construct a 24-mile, 48-inch diameter natural gas pipeline designed to transport 2.6 Bcf/d of regasified LNG from the site of our proposed Corpus Christi LNG receiving terminal, running northwesterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas transmission pipelines in south Texas, including pipelines operated by Texas Eastern Transmission Corporation, Gulf South Pipeline Company, L.P., Gulf Terra Intrastate, L.P. (Channel), Kinder Morgan Tejas Pipeline, L.P., Crosstex CCNG Marketing, Ltd., Transcontinental Gas Pipeline Corporation and Natural Gas Pipeline Company of America. We believe these existing pipelines are currently capable of transporting approximately 4.6 Bcf/d. It is possible that one or more other pipeline operators will undertake to build pipeline connections to the Corpus Christi LNG facility. We expect that constructing these pipeline connections will require far less capital and time than the construction of our Corpus Christi LNG facility. Our ultimate decisions regarding pipeline connection to the facility will depend upon future events, including, in particular, customer interest and general market demand for natural gas from the terminal.

Other sites

LNG receiving terminal operating costs

We anticipate that the annual fixed operating cost for each of our Sabine Pass and Corpus Christi LNG receiving terminals will be approximately $25 million to $30 million, assuming current estimates for staffing levels, maintenance costs and property taxes. Current tax estimates are based on our receiving tax abatements at each facility, without which our estimated taxes will be substantially greater. In addition, we believe that Corpus Christi LNG will incur approximately $10 million to $15 million in variable operating expenses for purchased power, assuming full utilization and current power rates.

J & S Cheniere

We hold a minority interest in J&S Cheniere. The majority interest in J&S Cheniere is held by J & S Group S.A., or J&S Group, a Luxembourg corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Under a stockholders agreement, we identify and assist with LNG-related business opportunities that we determine are appropriate for J&S Cheniere. We are not required to offer any particular business opportunities nor funding to J&S Cheniere. All financing of these business opportunities will be provided by J&S Group should it determine that a business opportunity is appropriate for J&S Cheniere. However, J&S Group is not required to fund any particular business opportunity. The stockholders agreement gives us the right to purchase additional

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shares up to a maximum of 50% of the outstanding shares of J&S Cheniere. The stockholders agreement also provides J&S Group the right to acquire all of our J&S Cheniere shares in the event that we experience a change in control (defined in the stockholders agreement to include a change in a majority of our board, the acquisition of more than 40% of our outstanding common stock other than as approved by our board of directors and a merger or consolidation that results in 50% or less of the surviving entity's voting securities being owned by the holders of our voting securities immediately prior to such transaction).

As its initial LNG business opportunity, in August 2003 J&S Cheniere chartered its first LNG tanker, the 130,000 cm-capacity Tenaga Empat. In January 2004 J&S Cheniere signed a transportation agreement with Sonatrach, the national oil company of Algeria, for the Tenaga Empat to actively transport LNG cargoes into the United States and Europe.

In August 2004, J&S Cheniere executed a time charter for its second LNG tanker for up to 10 years with Kawasaki Kisen Kaisha, Ltd., or K-Line, to charter a new build, 145,000 cm-capacity LNG tanker being constructed by Kawasaki Shipbuilding Corporation. The tanker is expected to be delivered in the fourth quarter of 2007.

In August 2004, J&S Cheniere also executed a time charter agreement for up to 10 years for its third LNG tanker with a joint venture company established by K-Line, Shoei Kisen Kaisha, Ltd. and others. The new build 154,200 cm-capacity LNG tanker is being constructed by Imabari Shipbuilding Co., Ltd. and is expected to be delivered in the fourth quarter of 2007.

J&S Cheniere entered into an agreement with us on December 23, 2003 under which J&S Cheniere has an option to enter into a TUA reserving up to 200 Mmcf/d of capacity at each of our Sabine Pass and Corpus Christi facilities. Following execution of the option agreement, an option fee of $1 million was paid to us by J&S Cheniere in January 2004. The option agreement may be terminated by J&S Cheniere and the option fee refunded in the event that we do not receive an order by FERC authorizing construction of at least one of the two facilities, or if we decide not to proceed with the development of at least one of the two facilities, in either case, before December 15, 2005. J&S Cheniere may exercise the option as to each facility by entering into a TUA no later than 60 days after receipt of written notification by us that such facility has been approved by FERC and all other approvals and permits have been received which are necessary to begin construction of the facility. The option agreement provides that any such TUA will provide for: (i) a fee per Mmbtu delivered equal to 8% of the then current price of natural gas at Henry Hub; (ii) an initial five-year term, with up to three additional five-year renewal periods upon payment of a $1 million fee for each renewal; and (iii) a minimum of two LNG vessel deliveries per month at the facility, at J&S Cheniere's election.

Competition

The volume of natural gas supply additions required to meet U.S. consumption needs is a function not only of demand growth, but also the decline in the underlying production base. In North America, this natural decline has been accelerating over the last decade, significantly increasing the need to bring on new supplies. According to a 2003 report by The National Petroleum Council, the number of natural gas wells in the U.S. in 1991 declined 17%, or 9 Bcf/d, by 1992, while wells in 2000 declined 27%, or 16 Bcf/d, by 2001.

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New supplies to replace North America's natural decline of natural gas production could be developed from a combination of the following sources: (i) existing producing basins in the United States, Canada and Mexico; (ii) frontier basins in Alaska, northern Canada and offshore deepwater; (iii) areas currently restricted from exploration and development due to public policies, such as areas in the Rocky Mountains and offshore Atlantic, Pacific and Gulf of Mexico coasts; and (iv) imported LNG. In addition, demand for natural gas could be met by alternative energy forms, including coal, hydroelectric, oil, wind, solar and nuclear energy. LNG will face competition from each of these energy sources.

EIA has reported that, as of December 31, 2003, there were over 6,000 Tcf of proved natural gas reserves worldwide, and we believe that LNG has the potential to be a significant new source of lower cost supply to North America. We will compete with other importers of LNG at existing and proposed North American LNG receiving terminals. There are currently four LNG receiving terminals operating in North America, which will compete with any terminals that we develop. We believe that all of the capacity at these terminals is committed to customers under long-term arrangements. There are currently 44 LNG receiving terminals in 12 countries, and we will compete with these and other proposed LNG receiving terminals worldwide to be the most economical delivery point for LNG production for both long-term contracted and spot volumes.

Oil and gas exploration and development

For a discussion about our oil and gas exploration and development business, please see our Annual Report on Form 10-K for the fiscal year ended December 31, 2003, as amended by Amendment Nos. 1 and 2, which is incorporated by reference in this prospectus supplement and the accompanying prospectus.

Governmental regulation

Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require the acquisition of certain consultations, permits and other authorizations before commencement of construction and operation of our LNG receiving terminals. This regulatory burden increases the cost of constructing and operating the LNG receiving terminals, and failure to comply with such laws could result in substantial penalties.

FERC

In order to site, construct and operate our proposed LNG receiving terminals, we must receive authorization from FERC under Section 3 of the Natural Gas Act of 1938, or NGA. FERC permitting process includes:

•: public notice;
•: data gathering and analysis at FERC's request;
•: issuance of a DEIS by FERC;
•: public meeting;
•: issuance of a FEIS by FERC; and

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•: FERC order authorizing construction.

In addition, an order from FERC authorizing construction of an LNG receiving terminal may be subject to specified conditions that must be satisfied prior to commencement of construction.

Freeport LNG

FERC granted Freeport LNG authorization under Section 3 of the NGA to site, construct and operate an LNG receiving terminal and to construct a 9.4 mile pipeline, together with related facilities, in Brazoria County, Texas. NGA Section 3 authorization was required because the Freeport LNG facility will be used to import natural gas from a foreign country. The Freeport LNG send-out pipeline will not interconnect with any interstate natural gas pipelines and will not be used to provide interstate transportation service under the NGA. Therefore, the proposed Freeport LNG 9.4 mile pipeline will be subject to FERC's more limited NGA Section 3 jurisdiction rather than the more extensive FERC regulation under Section 7 of the NGA related to facilities used to transport natural gas in interstate commerce.

Sabine Pass LNG/Corpus Christi LNG

The construction and operation of our proposed Sabine Pass and Corpus Christi LNG receiving terminals will also be subject to FERC's regulation under Section 3 of the NGA. However, unlike our Freeport LNG project, the Sabine Pass and Corpus Christi projects include interstate natural gas pipelines which will connect these proposed LNG facilities to the interstate natural gas pipeline grid. To the extent that we construct and operate interstate natural gas pipeline facilities, we must obtain authorization pursuant to Section 7 of the NGA to construct and operate these facilities and will be subject to FERC's regulation under NGA Section 7, including open access and tariff requirements. FERC's exercise of jurisdiction over interstate gas pipelines pursuant to NGA Section 7 is substantially broader than its exercise of jurisdiction over LNG terminals under NGA Section 3 and would continue as long as these pipelines are operated in interstate commerce.

Other Federal Governmental Permits, Approvals and Consultations

In addition to FERC authorization under Section 3 of the NGA, our construction and operation of LNG receiving terminals is also subject to additional federal permits, approvals and consultations required by certain other federal agencies, including: Advisory Counsel on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency and U.S. Department of Homeland Security.

Our LNG receiving terminals will also be subject to U.S. Department of Transportation siting requirements and regulations of the U.S. Coast Guard relating to facility security. Moreover, our LNG receiving terminals will also be subject to local and state laws, rules and regulations.

Environmental matters

Our LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. In some cases, these laws and regulations require us to obtain governmental authorizations before we may conduct certain activities or may require us to limit certain activities in order to protect endangered or threatened species or sensitive

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areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for pollution. As with the industry generally, compliance with these laws increases our overall cost of business. While these laws affect our capital expenditures and earnings, we believe that these regulations do not affect our competitive position in the industry because our competitors are similarly affected by these laws. Environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations. Environmental laws that may affect our operations include:

CERCLA

The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability, without regard to fault, on certain classes of persons who are considered to be responsible for the spill or release of a hazardous substance into the environment. Potentially liable persons include the owner or operator of the site where the release occurred and persons who disposed or arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for:

•: the costs of cleaning up the hazardous substances that have been released into the environment;
•: damages to natural resources; and
•: the costs of certain health studies.

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although CERCLA currently excludes petroleum, natural gas, natural gas liquids and liquefied natural gas from its definition of "hazardous substances," this exemption may be limited or modified by the United States Congress in the future.

Clean Air Act

Our operations may be subject to the federal Clean Air Act, or CAA, and comparable state and local laws. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations will be materially adversely affected by any such requirements.

Clean Water Act

Our operations are also subject to the federal Clean Water Act, or CWA, and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general

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permit. In addition, our operations, including construction of LNG receiving terminals, in areas deemed to be wetlands, or which otherwise involve discharges of dredged or fill material into navigable waters of the United States, may be subject to Army Corps of Engineers permitting requirements.

Solid Waste

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "hazardous wastes." In the event any hazardous wastes are generated in connection with our LNG operations, we may be subject to regulatory requirements affecting the handling, transportation, storage and disposal of such wastes.

Endangered Species

Our operations may be restricted by requirements under the Environmental Species Act, or ESA, which seeks to ensure that human activities do not jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

Litigation

We have been a party to various legal proceedings, which are incidental to the ordinary course of business, and may in the future be included in litigation in the ordinary course of business. Our management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. There are presently no threatened or pending legal matters that we believe would have a material impact on our consolidated results of operations, financial position or cash flows.

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Management

The individuals listed below serve as our executive officers, members of our board of directors, or both.

Name	Age	Position


Charif Souki	51	Director, Chairman of the Board of Directors, President and Chief Executive Officer
Walter L. Williams	76	Director, Vice Chairman of the Board of Directors
Don A. Turkleson	50	Senior Vice President & Chief Financial Officer, Secretary & Treasurer
Jonathan S. Gross	45	Senior Vice President—Exploration
Keith M. Meyer	47	Senior Vice President—LNG
Zurab S. Kobiashvili	62	Senior Vice President & General Counsel
Nuno Brandolini	50	Director
Keith F. Carney	48	Director
Paul J. Hoenmans	72	Director
David S. Kilpatrick	54	Director
J. Robinson West	58	Director

Charif Souki, a co-founder of Cheniere, is currently Chairman of our Board of Directors, President and Chief Executive Officer. On December 18, 2002, Mr. Souki assumed the positions of President and Chief Executive Officer. From September 1997 until June 1999, he was Co-Chairman of the Board of Directors, and he served as Secretary from July 1996 until September 1997. Mr. Souki has over 20 years of independent investment banking experience in the industry and has specialized in providing financing for promising microcap and small capitalization companies with an emphasis on the oil and gas industry. Mr. Souki received a B.A. from Colgate University and an M.B.A. from Columbia University. He also serves on the board of directors of Gryphon Exploration Company, an entity in which Cheniere owns 100% of the common stock (an effective 9.3% ownership interest upon conversion of Gryphon's convertible preferred stock).

Walter L. Williams has served as Vice Chairman of the Board of Directors since June 1999. He served as President and Chief Executive Officer from September 1997 until June 1999 and as Vice Chairman of the Board of Directors from July 1996 until September 1997. Prior to joining Cheniere, Mr. Williams spent 32 years as a founder and later Chairman and Chief Executive Officer of Texoil, Inc., a publicly-held Gulf Coast exploration and production company. Prior to that time, he was an independent petroleum consultant. Mr. Williams received a B.S. in petroleum engineering from Texas A&M University and is a Registered Engineer in Louisiana

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and Texas. He has served as a director and member of the Executive Committee of the Board of the Houston Museum of Natural Science.

Don A. Turkleson has served as Vice President and Chief Financial Officer, Secretary and Treasurer since December 1997 and became Senior Vice President in May 2004. Prior to joining Cheniere in 1997, Mr. Turkleson was employed by PetroCorp Incorporated from 1983 to 1996, as Controller until 1986, then as Vice President—Finance, Secretary and Treasurer. From 1975 to 1983, he worked as a Certified Public Accountant in the natural resources division of Arthur Andersen & Co. in Houston. Mr. Turkleson received a B.S. in accounting from Louisiana State University in 1975. He is a director and past Chairman of the Board of Neighborhood Centers, Inc., a nonprofit organization.

Jonathan S. Gross has served as Vice President-Exploration since October 2000. He served as Technology Manager from June 1999 through October 2000 and became Senior Vice President in May 2004. Mr. Gross began his career in 1981 with Amoco Production Company as an exploration geophysicist. While at Amoco, he held senior technical positions in both domestic and international basins. In 1998, he joined Zydeco Energy, Inc., where he served as economist, exploration risk specialist and project manager. Mr. Gross received a B.A. degree in geology from the University of Chicago, and he is a member of the American Association of Petroleum Geologists, the Society of Exploration Geophysicists, and the Houston Geological Society.

Keith M. Meyer has served as Vice President—LNG and as President of Cheniere LNG, Inc., a wholly-owned subsidiary of Cheniere, since June 2003 and became Senior Vice President—LNG in May 2004. From 2000 to 2003, Mr. Meyer was Vice President of Business Development, LNG and Supply for CMS Panhandle Companies, an interstate natural gas transmission system wholly-owned by CMS Energy and owner of Trunkline LNG, an LNG import terminal in Lake Charles, Louisiana. In that capacity, he oversaw all commercial aspects of Trunkline LNG's activities. Mr. Meyer also served as Executive Director of CMS Energy's international gas transmission activities. Prior to joining CMS in 1990, Mr. Meyer was with ANR Pipeline Company for 10 years in strategic planning and project development activities, serving also as Vice President of Marketing for the Empire State Pipeline in New York. He received a B.S. in finance from Wayne State University and an MBA from Rice University.

Zurab S. Kobiashvili was appointed Senior Vice President & General Counsel in May 2004. Prior to joining Cheniere, he was with Apache Corporation since 1994, initially as Vice President and General Counsel and most recently as Senior Vice President and General Counsel. Prior to Apache, he served as an officer and General Counsel of a number of public and private companies. He began his legal career with a New York City-based law firm and holds a B.S. from Brown University and a J.D. from the University of Virginia.

Nuno Brandolini is currently a director and a member of our Audit Committee and Compensation Committee. Mr. Brandolini has served since 1995 as Chairman and Chief Executive Officer of Scorpion Holdings, Inc., a private equity firm. Mr. Brandolini is also a founder and principal of Scorpion Capital Partners, L.P., a Small Business Investment Company. Prior to forming Scorpion Holdings, Mr. Brandolini served as Managing Director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Before joining Rosecliff, Mr. Brandolini was a Vice President at Salomon Brothers, Inc. where he was an investment banker involved in mergers and acquisitions in the Financial Entrepreneurial Group. Mr. Brandolini has also worked for Lazard Freres in New York and was President of The

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Baltheus Group, a merchant banking firm, and Executive Vice President of Logic Capital Corp., a venture capital firm. He currently serves on the board of the following private and public companies: Pac Pizza LLC; LifePoint, Inc.; The Original San Francisco Toymakers; and WalkAbout Computers. Mr. Brandolini was awarded a law degree by the University of Paris and received an M.B.A. from the Wharton School.

Keith F. Carney is currently the Lead Director of our Board of Directors, Chairman of our Compensation Committee and a member of our Audit Committee. Mr. Carney served as Chief Financial Officer and Treasurer from July 1996 through November 1997 and Executive Vice President from 1997 through August 2001. Since October 2001, Mr. Carney has been President of Dolomite Advisors, LLC, an investment firm. In 2001, he was elected a director to Cheniere. Mr. Carney also served as a member of the Audit Committee from 2001 until April 15, 2003. Prior to joining Cheniere, Mr. Carney was a securities analyst in the oil and gas exploration/production sector with Smith Barney, Inc. from 1992 to 1996. From 1982 to 1990, he was employed by Shell Oil as an exploration geologist, with assignments in the Gulf of Mexico, the Middle East and other areas. He received an M.S. in geology from Lehigh University in 1982 and an M.B.A.-Finance from the University of Denver in 1992.

Paul J. Hoenmans is currently a director and a member of our Compensation Committee and Audit Committee. Mr. Hoenmans has over 35 years of senior executive level experience in the industry. During that time, he has served Mobil Oil Corporation in various executive capacities, most recently as Director and Executive Vice President, with overall responsibility for policy, strategy, performance and stakeholder contact. From 1986 through 1996, he served as the President of Mobil Oil Corporation's Exploration & Producing Division, with worldwide responsibility for upstream operations. Mr. Hoenmans has held various other positions of senior executive level responsibility with Mobil since 1975, over both upstream and downstream operations worldwide throughout the Americas, Africa, Southeast Asia, the Middle East, Europe and Scandinavia. Mr. Hoenmans is a retired director of Xpronent, Inc., Veba Oel AG and Talisman Energy, Inc. He received a B.S. in civil engineering from the University of British Columbia.

David B. Kilpatrick is currently a director and Chairman of our Audit Committee. Mr. Kilpatrick has over 30 years of executive, management and operating experience in the oil and gas industry. Since 1998, he has been the President of Kilpatrick Energy Group, a consulting firm to oil and gas companies. Mr. Kilpatrick serves as a director on the boards of publicly traded PYR Energy Corporation and privately held Ensyn Petroleum International, Ltd. From 1996 to 1998, Mr. Kilpatrick was the President and Chief Operating Officer for Monterey Resources, Inc., an independent oil and gas company in California. From 1982 to 1996, he held various managerial positions at Santa Fe Energy Resources, an oil and gas production company. Mr. Kilpatrick is currently serving as a director of the California Independent Petroleum Association and the Independent Oil Producers Agency. He received a B.S. in petroleum engineering from the University of Southern California and a B.A. in geology and physics from Whittier College.

J. Robinson West is currently a director. Mr. West is the founder and Chairman of the Board of PFC Energy, a consulting business covering all aspects of the oil, gas and power business. Prior to founding PFC in 1984, Mr. West served in the Reagan Administration as Assistant Secretary of the Interior for Policy, Budget and Administration, with responsibility for United States offshore oil policy. He is currently a member of the Secretary of Energy Advisory Board, the National Petroleum Council and the Council on Foreign Relations, as well as President of the Wyeth Endowment for American Art. Mr. West serves on the board of directors of Key Energy Services, Inc. and Lambert Energy Advisory. He received a B.A. from the University of North Carolina at Chapel Hill and a J.D. from Temple University.

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Principal stockholders

The following table sets forth information, as of December 1, 2004, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director and each of the five most highly compensated executive officers, and by all directors and executive officers as a group.

Name	Amount and Nature of Beneficial Ownership		Percent of Class


Charif Souki	1,451,977	(1)	7.1	%
Walter L. Williams	308,215	(2)	1.5	%
Don A. Turkleson	274,298	(3)	1.3	%
Keith F. Carney	179,673		*
Jonathan S. Gross	161,415	(4)	*
Keith M. Meyer	121,549	(5)	*
Nuno Brandolini	83,006		*
Paul J. Hoenmans	83,006		*
David S. Kilpatrick	64,006	(6)	*
J. Robinson West	38,006	(7)	*
Zurab S. Kobiashvili	3,459	(8)	*
All Directors and Officers as a group (12 persons)	2,788,412	(9)	13.6	%

*: Less than 1%
(1): Includes 16,667 shares issuable upon exercise of warrants held by Mr. Souki which become exercisable within 60 days of the date of this prospectus supplement, 54,750 shares owned by Mr. Souki's wife, 800,000 shares held indirectly through a trust of which Mr. Souki is the sole beneficiary, and 60,000 shares held indirectly through those of Mr. Souki's children who share the same household. Excludes 16,666 shares issuable upon the exercise of options held by Mr. Souki but not exercisable within 60 days of the date of this prospectus supplement.
(2): Includes 12,500 shares issuable upon exercise of options held by Mr. Williams which become exercisable within 60 days of the date of this prospectus supplement and 10,000 shares owned by Mr. Williams' wife. Excludes 12,500 shares issuable upon the exercise of options held by Mr. Williams but not exercisable within 60 days of the date of this prospectus supplement.
(3): Includes 8,333 shares issuable upon exercise of currently exercisable options held by Mr. Turkleson and 8,000 shares held indirectly through Mr. Turkleson's children who share the same household. Excludes 8,334 shares issuable upon the exercise of options held by Mr. Turkleson but not exercisable within 60 days of the date of this prospectus supplement.
(4): Includes 8,333 shares issuable upon exercise of options held by Mr. Gross which become exercisable with 60 days of the date of this prospectus supplement. Excludes 8,334 shares issuable upon the exercise of options held by Mr. Gross but not exercisable within 60 days of the date of this prospectus supplement.
(5): Excludes 166,666 shares issuable upon the exercise of options held by Mr. Meyer but not exercisable within 60 days of the date of this prospectus supplement.
(6): Includes 50,000 shares issuable upon exercise of currently exercisable options held by Mr. Kilpatrick.
(7): Includes 25,000 shares issuable upon exercise of currently exercisable options held by Mr. West.
(8): Excludes 100,000 shares issuable upon exercise of options held by Mr. Kobiashvili but not exercisable within 60 days of the date of this prospectus supplement.
(9): Includes an aggregate of 75,000 shares issuable upon exercise of currently exercisable options, and 62,500 shares issuable upon exercise of options which become exercisable within 60 days of the date of this prospectus supplement. Excludes an aggregate of 345,833 shares issuable upon the exercise of options not exercisable within 60 days of the date of this prospectus supplement.

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Certain relationships and transactions

In December 2003, Cheniere LNG Services, Inc., or Cheniere LNG, a wholly-owned subsidiary of Cheniere, entered into a stockholders' agreement with J & S Group S.A. regarding the ownership and operation of J & S Cheniere S.A., a company in which the brother of Charif Souki, Cheniere's Chairman of the Board of Directors, President and Chief Executive Officer, is a director. In January 2004, J&S Cheniere paid us $1 million for an option to purchase LNG regasification capacity in each of our Sabine Pass and Corpus Christi LNG facilities. Cheniere LNG owns a minority interest in the stock of J&S Cheniere. See "Business—J & S Cheniere."

In conjunction with our private placement of equity in January 2004, placement fees were paid to T. R. Winston & Company, Inc., a company in which the son of Charif Souki, Cheniere's Chairman, President and Chief Executive Officer, is employed. Placement fees to T. R. Winston for such placement totaled $965,250.

All such transactions were approved by our board of directors, and we believe that each such transaction was on terms that were comparable to, or more favorable to us than, those that might have been obtained by us on an arm's length basis from unaffiliated parties.

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Underwriting

J. P. Morgan Securities Inc. is acting as sole book-running manager and joint lead manager for this offering, and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Petrie Parkman & Co., Inc. are also acting as joint lead managers. Subject to the terms and conditions set forth in an underwriting agreement, we have agreed to sell to each underwriter named below, and such underwriters have agreed to purchase, the number of shares of common stock set forth opposite their names below.

Underwriter		Number of shares


J.P. Morgan Securities Inc.		1,950,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated		1,450,000
Petrie Parkman & Co., Inc.		1,450,000
Pritchard Capital Partners LLC		150,000

Total		5,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase our common stock included in this offering are subject to certain conditions precedent customary for offerings of this type. The underwriters are obligated to purchase all of the shares of common stock offered by this prospectus supplement, other than those covered by the option described below, if they purchase any of these shares.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 750,000 additional shares of common stock at the public offering price less the underwriting discount set forth on the cover page of this prospectus supplement. The underwriters may exercise that option solely for the purpose of covering over-allotments, if any, in connection with this offering.

The following table shows the per share and total underwriting discounts that we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares.

	No Exercise		Full Exercise


Paid by us per share	$	2.70	$	2.70
Total paid by us	$	13,500,000	$	15,525,000

The representatives of the underwriters have advised us that the underwriters propose initially to offer such shares of common stock to the public at the public offering price set forth on the cover page of this prospectus supplement and to dealers at the public offering price less a concession not in excess of $1.62 per share. The underwriters may allow, and such dealers may reallow, a concession of not more than $0.10 per share to other dealers. After the public offering, the representatives may change the offering price and the other selling terms.

S-66

We and all of our directors and executive officers listed on page S-64 have agreed that, without the prior written consent of J.P. Morgan Securities Inc., on behalf of the underwriters, we and they will not, during the period ending 90 days after the date of this prospectus supplement:

•: offer, pledge, announce the intention to sell, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of directly or indirectly, any shares of our common stock or any securities convertible into or exercisable or exchangeable for our common stock; or
•: enter into any swap or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any such transaction described above is to be settled by delivery of our common stock or such other securities, in cash or otherwise.

The restrictions described in this paragraph do not apply to:

•: the sale of shares of our common stock to the underwriters in connection with this offering;
•: the granting by us of options to purchase shares of our common stock under existing employee stock plans;
•: the issuance by us of shares of our common stock upon the exercise of options granted under existing employee stock plans;
•: the granting by us of shares of our common stock under existing employee stock plans;
•: shares of our common stock acquired in open market transactions by any person other than us;
•: sales of shares of our common stock more than 30 days after the date of this prospectus supplement by some of our executive officers and one of our independent directors to pay for existing tax liabilities arising from the exercise of options to purchase shares of our common stock and awards of bonus shares of our common stock (up to an aggregate limit of $3.0 million for sales by all such persons combined);
•: the issuance by us of shares of our common stock in connection with one or more acquisitions by us of assets or equity interests (whether by mergers, exchanges of equity interests or otherwise);

provided that in the case of the last transaction above, each transferee or recipient agrees to be subject to the restrictions described in the immediately preceding paragraph.

J.P. Morgan Securities Inc. may release any of the securities subject to these lock-up agreements at any time without notice. J.P. Morgan Securities Inc. has advised us that it will determine to waive or shorten the lock-ups on a case-by-case basis after considering such factors as the current equity market conditions, the performance of the price of our common stock since the offering and the likely impact of any waiver on the price of our common stock, and the requesting party's reason for making the request. J.P. Morgan Securities Inc. has advised us that it has no present intent or arrangement to release any of the securities subject to these lock-up agreements.

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We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments that the underwriters may be required to make because of those liabilities.

The underwriters may engage in stabilizing transactions, syndicate covering transactions and penalty bids in accordance with Rule 104 under the Securities Exchange Act of 1934 in connection with this offering. Stabilizing transactions permit bids to purchase the common stock so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the common stock in the open market following completion of this offering to cover all or a portion of a syndicate short position created by the underwriters selling more shares of common stock in connection with this offering than they are committed to purchase from us. In addition, the underwriters may impose "penalty bids" under contractual arrangements between the underwriters and dealers participating in this offering whereby they may reclaim from a dealer participating in this offering the selling concession with respect to shares of common stock that are distributed in this offering but subsequently purchased for the account of the underwriters in the open market. Such stabilizing transactions, syndicate covering transactions and penalty bids may result in the maintenance of the price of the common stock at a level above that which might otherwise prevail in the open market. None of the transactions described in this paragraph is required, and, if any are undertaken, they may be discontinued at any time.

We estimate that the total expenses of this offering will be approximately $430,000, excluding the underwriting discounts.

Certain of the underwriters and their affiliates have provided in the past to us and our affiliates and may provide from time to time in the future certain commercial banking, financial advisory, investment banking and other services for us and such affiliates in the ordinary course of their business, for which they have received and may continue to receive customary fees and commissions. In particular, Petrie Parkman & Co., Inc. is currently engaged by us to raise private equity, including financing related to the Chevron USA agreement, for which it may receive a transaction fee. In addition, from time to time, certain of the underwriters and their affiliates may effect transactions for their own account or the account of customers, and hold on behalf of themselves or their customers, long or short positions in our debt or equity securities or loans, and may do so in the future.

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Legal matters

The validity of the issuance of the shares of common stock offered hereby has been passed upon for us by Andrews Kurth LLP, Houston, Texas. Legal matters in connection with this offering will be passed upon for the underwriters by Cahill Gordon & Reindel LLP, New York, New York.

Experts

The consolidated financial statements of Cheniere Energy, Inc. at December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003 appearing in our Annual Report on Form 10 K/A for the fiscal year ended December 31, 2003, which was filed with the SEC on July 20, 2004, have been audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP (formerly Mann Frankfort Stein & Lipp CPAs, L.L.P.), an independent registered public accounting firm, as set forth in their report thereon included therein and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Gryphon Exploration Company as of December 31, 2002, and for each of the years in the two-year period ended December 31, 2002, have been incorporated by reference herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2003, which was filed with the SEC on July 20, 2004, and upon the authority of such firm as experts in accounting and auditing.

The financial statements of Freeport LNG Development, L.P. as of December 31, 2003 and for the year then ended and for the period from inception (December 1, 2002) through December 31, 2003 appearing in our Annual Report on Form 10-K, which was filed with the SEC on March 25, 2004, for the fiscal year ended December 31, 2003 have been audited by Hein & Associates LLP, independent auditors, as set forth in their report thereon included therein and incorporated herein by reference. Such financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

On October 22, 2002, we filed a Current Report on Form 8-K announcing that we had engaged Mann Frankfort Stein & Lipp CPAs, L.L.P. as independent auditors for the fiscal year ending December 31, 2002, replacing PricewaterhouseCoopers LLP. The decision to change independent public accountants was not the result of any disagreement with PricewaterhouseCoopers LLP on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of PricewaterhouseCoopers LLP, would have caused them to make a reference thereto in their report on the financial statements of Cheniere Energy, Inc. for the two years ended December 31, 2001 and the subsequent interim period through such dismissal.

The information incorporated by reference into this prospectus supplement and the accompanying prospectus regarding our estimated proved reserves are based on the reports generated by our independent petroleum engineers, Sharp Petroleum Engineering, Inc. in 2003 and Ryder Scott Company in 2001 and substantially, but not wholly, based on the report generated by Ryder Scott Company in 2002.

S-69

Interests of named experts and counsel

The validity of the issuance of the shares of common stock offered hereby has been passed upon for us by Andrews Kurth LLP. Attorneys at the law firm of Andrews Kurth LLP beneficially own 8,500 shares of our common stock.

S-70

Glossary of energy terms

•: Bcf means billion cubic feet
•: Bcf/d means billion cubic feet per day
•: Bcfe means billion cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one barrel (or 42 United States gallons liquid volume) of crude oil, condensate and natural gas liquids
•: cm means cubic meter
•: LNG means liquefied natural gas
•: Mcf means thousand cubic feet
•: Mmcf means million cubic feet
•: Mmcf/d means million cubic feet per day
•: Mmbtu means million British thermal units
•: Tcf means trillion cubic feet

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Where you can find more information

We file annual, quarterly and special reports, proxy and information statements and other information with the SEC pursuant to the Securities Exchange Act of 1934, as amended, or the Exchange Act. The SEC maintains an Internet site at http://www.sec.gov that contains those reports, proxy and information statements and other information regarding us. You may also inspect and copy those reports, proxy statements and other information at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on operation of the Public Reference Room. You may also inspect and copy those reports, proxy and information statements and other information at the offices of the American Stock Exchange, 86 Trinity Place, New York, New York 10006, the exchange on which our common stock is listed.

We have filed with the SEC a registration statement on Form S-3 covering the securities offered by this prospectus supplement and the accompanying prospectus. This prospectus supplement and the accompanying prospectus are only a part of the registration statement and do not contain all of the information in the registration statement. For further information on us and the securities that may be offered, please review the registration statement and the exhibits that are filed with it. Statements made in this prospectus supplement or the accompanying prospectus that describe documents may not necessarily be complete. We recommend that you review the documents that we have filed with the registration statement to obtain a more complete understanding of those documents.

The SEC allows us to "incorporate by reference" information into this prospectus supplement, which means that we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus supplement and the accompanying prospectus, except for any information superseded by information in this prospectus supplement or in any subsequent prospectus supplement. This prospectus supplement and the accompanying prospectus incorporate by reference the documents set forth below that we previously filed with the SEC. These documents contain important information about us and are an important part of this prospectus supplement and the accompanying prospectus.

The following documents that we have filed with the SEC (File No. 001-16383) are incorporated by reference into this prospectus supplement and the accompanying prospectus:

•: Annual Report on Form 10-K for the fiscal year ended December 31, 2003, filed on March 25, 2004, as amended by Form 10-K/As filed on May 26, 2004 and July 20, 2004;
•: Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2004, filed on November 15, 2004;
•: Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004, filed on August 10, 2004;
•: Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2004, filed on May 13, 2004;
•: Definitive Proxy Statement on Schedule 14A, filed on April 6, 2004;

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•: Current Reports on Form 8-K filed on January 14, 2004, January 16, 2004, January 27, 2004, February 3, 2004, March 2, 2004, May 18, 2004, June 3, 2004, June 23, 2004, July 7, 2004, September 3, 2004, September 9, 2004, October 14, 2004, November 8, 2004, November 9, 2004 (two) and November 16, 2004; and
•: The description of our common stock contained in our Registration Statement on Form 8-A, filed on March 2, 2001, and any amendment or report filed for the purpose of updating that description.

All documents that we file pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this prospectus supplement and until our offering is completed will be deemed to be incorporated by reference into this prospectus supplement and the accompanying prospectus and will be a part of this prospectus supplement and the accompanying prospectus from the date of the filing of the document. Any statement contained in a document incorporated or deemed to be incorporated by reference in this prospectus supplement and the accompanying prospectus will be deemed to be modified or superseded for purposes of this prospectus supplement to the extent that a statement contained in this prospectus supplement or in any other subsequently filed document that also is or is deemed to be incorporated by reference in this prospectus supplement and the accompanying prospectus modifies or supersedes that statement. Any statement that is modified or superseded will not constitute a part of this prospectus supplement and the accompanying prospectus, except as modified or superseded.

We will provide without charge to each person, including any beneficial owner, to whom a copy of this prospectus supplement and the accompanying prospectus have been delivered, upon written or oral request, a copy of any or all of the information incorporated by reference in this prospectus supplement and the accompanying prospectus but not delivered herewith, other than the exhibits to those documents, unless the exhibits are specifically incorporated by reference into the information that this prospectus supplement and the accompany prospectus incorporate. You should direct a request for copies to us as follows:

Cheniere Energy, Inc.
Attention: Don A. Turkleson, Chief Financial Officer
717 Texas Avenue, Suite 3100
Houston, Texas 77002
(713) 659-1361

If you have any other questions regarding us, please contact our Vice President—Investor Relations in writing at Cheniere Energy, Inc., 717 Texas Avenue, Suite 3100, Houston, Texas 77002, Contact: David E. Castaneda, or by telephone at 713-265-0202 or e-mail at Info@Cheniere.com.

You can access electronic copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and all amendments to those reports, free of charge, on our website at http://www.cheniere.com. Access to those electronic filings is available as soon as reasonably practicable after filing with, or furnishing to, the SEC. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this prospectus supplement or the accompanying prospectus.

S-73

PROSPECTUS

CHENIERE ENERGY, INC.
$600,000,000
COMMON STOCK
PREFERRED STOCK
SENIOR UNSECURED DEBT SECURITIES
SENIOR SUBORDINATED DEBT SECURITIES
WARRANTS
UNITS
GUARANTEES

By this prospectus, we may from time to time offer and sell in one or more offerings up to an aggregate of $600,000,000 of the following securities:

(1) shares of common stock;

(2) shares of preferred stock, in one or more series, which may be convertible into or exchangeable for debt securities or common stock;

(3) senior unsecured debt securities, which may be convertible into or exchangeable for common stock or preferred stock;

(4) senior subordinated debt securities, which may be convertible into or exchangeable for common stock or preferred stock;

(5) warrants to purchase common stock, preferred stock, debt securities or units;

(6) units consisting of any combination of common stock, preferred stock, debt securities or warrants; and/or

(7) guarantees of debt securities issued by Cheniere Energy, Inc.

This prospectus provides a general description of the securities we may offer. Supplements to this prospectus will provide the specific terms of the securities that we actually offer, including the offering prices. You should carefully read this prospectus, any applicable prospectus supplement and any information under the heading "Where You Can Find More Information" before you invest in any of these securities. This prospectus may not be used to sell securities unless it is accompanied by a prospectus supplement that describes those securities.

We may sell these securities to or through underwriters, to other purchasers and/or through agents. Supplements to this prospectus will specify the names of any underwriters or agents.

Our common stock is listed for trading on the American Stock Exchange under the symbol "LNG."

Investing in our securities involves risks. Please read "Risk factors" beginning on page 6 of this prospectus.

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.

The date of this prospectus is September 10, 2004.

Table of contents

About this prospectus		1
Where you can find more information		1
Cautionary statement regarding forward-looking statements		3
Cheniere Energy, Inc.		5
Risk factors		6
Use of proceeds		17
Ratios of earnings to fixed charges		18
Description of capital stock		19
Description of debt securities		23
Description of warrants		30
Description of units		31
Plan of distribution		31
Legal matters		32
Experts		33
Interests of named experts and counsel		33

About this prospectus

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or SEC, utilizing a "shelf" registration process. Under this shelf registration process, we may sell any combination of the securities described in this prospectus in one or more offerings up to a total offering price of $600,000,000. This prospectus provides you with a general description of the securities we may offer. Each time we offer to sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities offered by us in that offering. The prospectus supplement may also add, update or change information contained in this prospectus. If there is any inconsistency between the information in this prospectus and any prospectus supplement, you should rely on the information provided in the prospectus supplement. This prospectus does not contain all of the information included in the registration statement. The registration statement filed with the SEC includes exhibits that provide more details about the matters discussed in this prospectus. You should carefully read this prospectus, the related exhibits filed with the SEC and any prospectus supplement, together with the additional information described below under the heading "Where You Can Find More Information."

You should rely only on the information contained or incorporated by reference in this prospectus and in any accompanying prospectus supplement. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer of the securities covered by this prospectus in any state where the offer is not permitted. You should assume that the information appearing in this prospectus, any prospectus supplement and any other document incorporated by reference is accurate only as of the date on the front cover of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

Under no circumstances should the delivery to you of this prospectus or any exchange or redemption made pursuant to this prospectus create any implication that the information contained in this prospectus is correct as of any time after the date of this prospectus.

This prospectus may not be used to sell securities unless it is accompanied by a prospectus supplement that describes those securities.

As used in this prospectus, "Cheniere," "we," "us" and "our" refer to Cheniere Energy, Inc. and its subsidiaries unless otherwise indicated. In this prospectus, we sometimes refer to the debt securities, common stock, preferred stock, warrants and units collectively as the "securities."

Where you can find more information

We file annual, quarterly and special reports, proxy and information statements and other information with the SEC pursuant to the Securities Exchange Act of 1934, as amended ("Exchange Act"). The SEC maintains an Internet site at http://www.sec.gov that contains those reports, proxy and information statements and other information regarding us. You may also inspect and copy those reports, proxy statements and other information at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on operation of the Public Reference Room. You may also inspect and copy those reports, proxy and information statements and other information

at the offices of the American Stock Exchange, 86 Trinity Place, New York, New York 10006, the exchange on which our common stock is listed.

We have filed with the SEC a registration statement on Form S-3 covering the securities offered by this prospectus. This prospectus is only a part of the registration statement and does not contain all of the information in the registration statement. For further information on us and the securities that may be offered, please review the registration statement and the exhibits that are filed with it. Statements made in this prospectus that describe documents may not necessarily be complete. We recommend that you review the documents that we have filed with the registration statement to obtain a more complete understanding of those documents.

The SEC allows us to "incorporate by reference" information into this prospectus, which means that we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus, except for any information superseded by information in this prospectus or in any prospectus supplement. This prospectus incorporates by reference the documents set forth below that we previously filed with the SEC. These documents contain important information about us and are an important part of this prospectus.

The following documents that we have filed with the SEC (File No. 001-16383) are incorporated by reference into this prospectus:

•: Annual Report on Form 10-K for the fiscal year ended December 31, 2003, filed on March 25, 2004, as amended by Form 10-K/As filed on May 26, 2004 and July 20, 2004;
•: Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004, filed on August 10, 2004;
•: Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2004, filed on May 13, 2004;
•: Definitive Proxy Statement on Schedule 14A, filed on April 6, 2004;
•: Current Reports on Form 8-K filed on January 14, 2004, January 16, 2004, January 27, 2004, February 3, 2004, March 2, 2004, May 18, 2004, June 3, 2004, June 23, 2004, July 7, 2004 and September 3, 2004; and
•: The description of our common stock contained in our Registration Statement on Form 8-A, dated March 1, 2001, filed on March 2, 2001, and any amendment or report filed for the purpose of updating that description.

All documents that we file or furnish pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this prospectus and until our offering is completed, or after the date of the registration statement of which this prospectus forms a part and prior to effectiveness of the registration statement, will be deemed to be incorporated by reference into this prospectus and will be a part of this prospectus from the date of the filing of the document. Any statement contained in a document incorporated or deemed to be incorporated by reference in this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document that also is or is deemed to be incorporated by reference in this prospectus modifies or supersedes that statement. Any statement that is

modified or superseded will not constitute a part of this prospectus, except as modified or superseded.

We will provide without charge to each person, including any beneficial owner, to whom a copy of this prospectus has been delivered, upon written or oral request, a copy of any or all of the information incorporated by reference in this prospectus but not delivered with the prospectus, other than the exhibits to those documents, unless the exhibits are specifically incorporated by reference into the information that this prospectus incorporates. You should direct a request for copies to us as follows:

Cheniere Energy, Inc.
Attention: Don A. Turkleson, Chief Financial Officer
717 Texas Avenue, Suite 3100
Houston, Texas 77002
(713) 659-1361

If you have any other questions regarding us, please contact our Investor Relations Department in writing at Cheniere Energy, Inc., 717 Texas Avenue, Suite 3100, Houston, Texas 77002, Contact: David E. Castaneda, or by telephone at 1-888-948-2036 or e-mail at Info@Cheniere.com.

Cautionary statement
regarding forward-looking statements

The information discussed in this prospectus, our filings with the SEC and our public releases include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended ("Securities Act"), and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included herein or incorporated herein by reference are "forward-looking statements." Included among "forward-looking statements" are, among other things: statements regarding our business strategy, plans and objectives; statements expressing beliefs and expectations regarding the development of our LNG receiving terminal business; statements expressing beliefs and expectations regarding our ability to successfully raise the additional capital necessary to meet our obligations under our current exploration agreements; statements expressing beliefs and expectations regarding our ability to secure the leases necessary to facilitate anticipated drilling activities; statements expressing beliefs and expectations regarding our ability to attract additional working interest owners to participate in the exploration and development of our exploration areas; and statements about non-historical information. These forward-looking statements are identified by the use of terms and phrases such as "expect," "estimate," "project," "plan," "believe," "achievable," "anticipate" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and

uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this prospectus.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in "Risk Factors" beginning on page 6. For additional information regarding risks and uncertainties, please read our other filings with the SEC under the Exchange Act and the Securities Act, particularly under "Management's Discussion and Analysis of Financial Condition and Results of Operation" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements.

Cheniere Energy, Inc.

We are a Houston-based company engaged primarily in the development of a liquefied natural gas, or LNG, receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

Our LNG receiving terminal projects include facilities to receive deliveries of LNG from LNG ships, to store LNG temporarily, to process LNG to return it to a gaseous state and to deliver gas to pipelines for transportation to purchasers. We have been developing our LNG business for over three years and have secured sites along the U.S. Gulf Coast for the development of LNG receiving terminals. We have commenced development of our Freeport, Texas, Sabine Pass, Louisiana, and Corpus Christi, Texas sites. We are still evaluating the future development of terminals in other locations, including Brownsville, Texas and Mobile, Alabama.

A substantial portion of our assets are held by or under our four wholly-owned operating subsidiaries: Cheniere LNG, Inc., Cheniere LNG Services, Inc., Cheniere Energy Operating Co., Inc. and Cheniere-Gryphon Management, Inc. We conduct most of our operations through one or more of these subsidiaries, including our operations relating to our development of an LNG receiving terminal business.

We have been publicly traded since July 3, 1996 under the name Cheniere Energy, Inc. Our corporate offices are located at 717 Texas Avenue, Suite 3100, Houston, Texas 77002. Our telephone number is (713) 659-1361.

Risk factors

The securities to be offered by this prospectus may involve a high degree of risk. When considering an investment in any of the securities, you should consider carefully all of the risk factors described below and any similar information contained in any Annual Report on Form 10-K or other document filed by us with the SEC after the date of this prospectus. If applicable, we will include in any prospectus supplement a description of those significant factors that could make the offering described in the prospectus supplement speculative or risky.

Risk factors related to us as an early stage company

We are subject to the expenses, difficulties and uncertainties generally associated with early stage companies.

We have a limited operating history with respect to our oil and gas exploration activities, and we have not yet started operating any LNG receiving facilities. We face all of the risks inherent in the establishment and growth of any new business. From our inception, we have incurred losses and may continue to incur losses, depending on whether we generate sufficient revenue either from LNG receiving operations or from producing reserves acquired through acquisitions or drilling activities. For the past several years, we dedicated a significant portion of our investment capital toward the development of LNG receiving terminals rather than to our oil and gas exploration activities, and we do not anticipate that our LNG receiving operations will generate revenues before the second half of 2007. Additionally, we may be unable to implement and complete our business plan, and our business may be ultimately unsuccessful. These factors make evaluating our business and forecasting our future operating results difficult. Furthermore, any continued losses and any delays in the implementation or completion of our business plan may have a material adverse effect on our business, our results of operations, our financial condition and the market price of our common stock.

We depend on key personnel and could be seriously harmed if we lost their services.

Risk factors related to our LNG receiving terminal development business

The construction of LNG receiving facilities is subject to various development risks.

We are involved in the development of several LNG receiving facilities. The construction of these projects is subject to the risks of cost overruns and delays. Key factors that may affect the timing and outcome of such projects include, but are not limited to: project approval by joint venture partners; identification of additional participants to reach optimum levels of participation; timely issuance of necessary permits, licenses and approvals by governmental

agencies and third parties; sufficient project and other financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; marine congestion; environmental conditions; weather conditions; unforeseen events, such as explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

Substantial capital will be needed in order to develop each LNG receiving terminal. We will need to obtain funding for our LNG projects form third-party sources. The failure to obtain capital on terms acceptable to us would inhibit the development of our LNG receiving terminals, which would likely have a material adverse effect on our business, results of operation and financial condition.

If completion of the LNG receiving facilities is delayed beyond the estimated development periods, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facilities would also cause a delay in the receipt of revenues projected from operation of the facilities, which may cause our business, results of operations and financial condition to be substantially harmed. The completion of the LNG receiving facilities could also be impacted by the availability or construction of sufficient LNG vessels.

Failure to obtain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminal business could have a detrimental effect on our LNG projects and on our company.

We are currently focusing our efforts and resources on developing our LNG receiving facilities. The transportation of LNG is highly regulated, and we have yet to obtain several governmental and regulatory approvals and permits required in order to complete and maintain our LNG projects. We cannot determine the amount of time it may take to obtain the approvals and permits necessary to proceed with the construction and operation of an LNG receiving terminal. We have no control over the outcome of the review and approval process. If we are unable to obtain the approvals and permits, we may not be able to recover our investment in the project. In addition, failure to obtain these approvals and permits may have a material adverse effect on our business, results of operations and financial condition.

Failure of LNG to become a competitive factor in the U.S. oil and gas industry could have a detrimental effect on our ability to implement and complete our business plan.

In the United States, due mainly to an abundant supply of natural gas, LNG has not historically been a major energy source. Furthermore, LNG may not become a competitive factor in the U.S. oil and gas industry. The failure of LNG to become a competitive supply alternative to domestic natural gas and other import alternatives may have a material adverse effect on our ability to implement and complete our business plan as well as our business, results of operations and financial condition.

We may have difficulty obtaining enough customers to generate a sufficient amount of revenue to recover our expenses incurred to enter the LNG receiving facilities market.

We anticipate that we will incur significant costs as we enter the LNG receiving facilities market and pursue customers by utilizing a variety of marketing methods. In order for us to recover these expenses, we must attract and retain a sufficient number of customers to our LNG receiving facilities.

We may experience difficulty attracting customers because we are a small company with no operating history in the LNG business. A major focus of our marketing efforts will be to convince customers that the terminal sites we are developing will be approved and that we will secure adequate financing for their construction. If our marketing strategy is not successful, our business, results of operations, and financial condition will be materially adversely affected.

We are subject to fluctuations in energy prices or the supply of LNG that would be particularly harmful to the development of our LNG receiving terminal business because of its developmental stage.

If LNG prices are higher than prices of domestically produced natural gas or natural gas derived from other sources, our ability to compete with such suppliers may be negatively impacted. In addition, in the event the supply of LNG is limited or restricted for any reason, our ability to profitably operate an LNG receiving facility could be materially impacted. Revenues generated by an LNG receiving terminal depend on the volume of LNG processed and the price of the natural gas produced, both of which can be affected by the price of natural gas and natural gas liquids.

Risk factors related to our exploration and development business

We are subject to significant exploration risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits.

Our exploration activities involve significant risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits. The wells we drill may not discover any oil or gas. Further, there is no way to know in advance of drilling and testing whether any prospect will yield oil or gas in sufficient quantities to make money for us. In addition, we are highly dependent on seismic activity and the related application of new technology as a primary exploration methodology. This methodology, however, requires greater pre-drilling expenditures than traditional drilling strategies. Even when fully used and properly interpreted, 3D seismic data can only assist us in identifying subsurface reservoirs and hydrocarbon indicators, and will not allow us to determine conclusively if hydrocarbons will in fact be present and recoverable. If our exploration efforts are unsuccessful, our business, results of operations and financial condition will be substantially harmed.

We may not be able to acquire the oil and gas leases we need to sustain profitable operations.

In order to engage in oil and gas exploration in the areas covered by our 3D seismic data, we must first acquire rights to conduct exploration and recovery activities on such properties. We may not be successful in acquiring farm-outs (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by

drilling one or more wells), seismic permits, lease options, leases or other rights to explore for or recover oil and gas. Both the U.S. Department of the Interior and the States of Texas and Louisiana award oil and gas leases on a competitive bidding basis. Non-governmental owners of the onshore mineral interests within the area covered by our exploration program are not obligated to lease their mineral rights to us except where we have already obtained lease options. In addition, other major and independent oil and gas companies with financial resources significantly greater than ours may bid against us for the purchase of oil and gas leases. If we are unsuccessful in acquiring these leases, permits, options and other interests, the area covered by our 3D seismic data that could be explored through drilling will be significantly reduced, and our business, results of operations and financial condition will be substantially harmed.

If we are unable to obtain satisfactory turnkey contracts, we may have to assume additional risks and expenses when drilling wells.

We anticipate that any wells drilled in which we have an interest will be drilled by established industry contractors under turnkey contracts that limit our financial and legal exposure. Under a turnkey drilling contract, a negotiated price is agreed upon and the money placed in escrow. The contractor then assumes all of the risk and expense, including any cost overruns, of drilling a well to contract depth and completing any agreed upon evaluation of the wellbore. Upon performance of all these items, the escrowed money is released to the contractor.

Circumstances may arise, however, where a turnkey contract is not economically beneficial to us or is otherwise unobtainable from proven industry contractors. In such instances, we may decide to drill wells on a day-rate basis. Under a day-rate drilling contract, the operator pays an agreed sum for each day of drilling required to reach contract depth. All risk and expense of drilling a well to total depths lies with the operator in day-rate contracts. The drilling of such test wells would subject us to the usual drilling hazards such as cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. We would also be liable for any cost overruns attributable to drilling problems that otherwise would have been covered by a turnkey contract. These liabilities, if incurred, may have a materially adverse impact on our business, results of operations and financial condition.

If we are unsuccessful at marketing our oil and gas at commercially acceptable prices, our profitability will decline.

Our ability to market oil and gas at commercially acceptable prices depends on, among other factors, the following:

•: the availability and capacity of gathering systems and pipelines;
•: federal and state regulation of production and transportation;
•: changes in supply and demand; and
•: general economic conditions.

Our inability to respond appropriately to changes in these factors could negatively effect our profitability.

Shortage of rigs, equipment, supplies or personnel may restrict our operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rises with increases in the number of active rigs in service. Shortages of drilling rigs, equipment or supplies could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

We depend on industry partners and could be seriously harmed if they do not perform satisfactorily, which is usually not within our control.

Because we have few employees and limited operating revenues, we are and will continue to be largely dependent on industry partners for the success of our oil and gas exploration projects. We could be seriously harmed if we fail to attract industry partners to participate in the drilling of prospects which we identify or if our industry partners do not perform satisfactorily on projects that affect us. We often have and will continue to have no control over factors that would influence the performance of our partners.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future net cash flows.

Numerous uncertainties, including those beyond our control, are inherent in estimating quantities of proved oil and gas reserves. Information incorporated by reference into this prospectus for 2003 relating to estimates of our proved reserves is based on reports prepared by Sharp Petroleum Engineering, Inc. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows may vary considerably from the actual results because of a number of variable factors and assumptions involved. These include:

•: historical production from the area compared with production from other producing areas;
•: the effects of regulation by governmental agencies;
•: future oil and gas prices;
•: operating costs;
•: severance and excise taxes;
•: development costs; and
•: workover and remedial costs.

Therefore, the estimates of the quantities of oil and gas and the expected future net cash flows computed by different engineers or by the same engineers (but at different times) may vary significantly. The actual production, revenues and expenditures related to our reserves may vary materially from the engineers' estimates. In addition, we may make changes to our

estimates of reserves and future net cash flows. These changes may be based on the following factors:

•: production history;
•: results of future development;
•: oil and gas prices;
•: performance of counterparties under agreements to which we are a party; and
•: operating and development costs.

Do not interpret the PV-10 values incorporated by reference into this prospectus as the current market value of our properties' estimated oil and gas reserves. According to the SEC, the PV-10 is generally based on prices and costs as of the date of the estimate. In contrast, the actual future prices and costs may be materially higher or lower. Actual future net cash flows may also be affected by the following factors:

•: the amount and timing of actual production;
•: the supply of, and demand for, oil and gas;
•: the curtailment or increases in consumption by natural gas purchasers; and
•: the changes in governmental regulations or taxation.

The timing in producing and the costs incurred in developing and producing oil and gas will affect the timing of actual future net cash flows from proved reserves. Ultimately, the timing will affect the actual present value of oil and gas. In addition, the SEC requires that we apply a 10% discount factor in calculating PV-10 for reporting purposes. This is not necessarily the most appropriate discount factor to apply because it does not take into account the interest rates in effect, the risks associated with us and our properties, or the oil and gas industry in general.

Because of our lack of diversification, factors harming the oil and gas industry in general, including downturns in prices for oil and gas, would be especially harmful to us.

We are an independent energy company and are not actively engaged in any other industry. Our revenues and results of operation are substantially dependent on the oil and gas industry in general and the prevailing prices for oil and gas in particular. Circumstances that harm the oil and gas industry in general will have an especially harmful effect on us. Oil and gas prices have been and are likely to continue to be volatile and subject to wide fluctuations in response to any of the following factors:

•: relatively minor changes in the supply of and demand for oil and gas;
•: political conditions in international oil producing regions;
•: the extent of domestic production and importation of oil in relevant markets;
•: the level of consumer demand;
•: weather conditions;
•: the competitive position of oil or gas as a source of energy as compared with other energy sources;

•: the refining capacity of oil purchasers; and
•: the effect of federal and state regulation on the production, transportation and sale of oil and gas.

It is likely that adverse changes in the oil and gas market or the regulatory environment would have an adverse effect on our business, results of operations and financial condition, including our ability to develop and implement our LNG project and to obtain capital from lending institutions, industry participants, private or public investors or other sources.

Risk factors related to our business in general

Our future growth and profitability are highly dependent on the development of our LNG receiving terminal business and the success of our exploration program.

Historically, the primary focus of our operations has been identifying drilling prospects, but in recent years we have focused on developing our LNG receiving facilities. Almost all of the assets on our balance sheet are represented by investments to date in our exploration program, including related seismic data. Our drilling activity in 1999 through 2003, to date, has established only limited proved reserves (oil and gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions). Furthermore, we have achieved only limited oil and gas production as of the date of this prospectus. For the past several years, we dedicated a significant portion of our investment capital toward the development of LNG receiving terminals rather than to our oil and gas exploration activities, and we do not anticipate that our LNG receiving operations will generate operating revenues before 2007.

Our future growth and profitability depend heavily on the development of our LNG receiving facilities and the success of our exploration program in locating additional proved reserves and achieving additional oil and gas production. Failure to develop our LNG receiving facilities or to locate such additional reserves and achieve additional production may have a material adverse effect on our business, results of operations and financial condition.

We experience intense competition in the energy industry, which may make it difficult for us to succeed.

The energy industry is highly competitive. If we are unable to compete effectively, we will not succeed. A number of factors may give our competitors advantages over us. For example, most of our current and potential competitors have significantly greater financial resources and a significantly greater number of experienced and trained managerial and technical personnel than we do. In addition, the businesses of such competitors are in many cases more diversified than ours. We may not be able to compete effectively with such companies. Moreover, the energy industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Increased competition causing excess capacity and depressed prices could have a substantially negative impact on our operating revenues.

We may not be able to obtain additional financing on terms that are acceptable to us, which could harm our ability to conduct business.

As of June 30, 2004, we had $11,752,498 of current assets and working capital of $8,446,404. We will need additional capital for a number of purposes. If we are unable to obtain additional financing on terms acceptable to us, it could significantly harm our ability to conduct our business, including our ability to construct LNG terminals and our ability to take advantage of opportunities that come from our exploration program. We will need substantial additional funds to execute our plan for developing and implementing an LNG receiving terminal business, including engineering, environmental, marine, regulatory, construction and legal work, including any such work involved in permitting and Federal Energy Regulatory Commission, or FERC, filings related to our development of the Corpus Christi and Sabine Pass LNG receiving terminals and related pipelines.

Obtaining additional capital may result in an adverse effect on our business.

Additional capital could be obtained from a combination of funding sources, many of which may have a material adverse effect on our business, results of operations and financial condition. These potential funding sources include:

•: cash flow from operating activities, which is sensitive to prices we receive for our oil and natural gas;
•: borrowings from financial institutions, which may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or pay dividends;
•: debt offerings, which would increase our leverage and add to our need for cash to service such debt;
•: additional offerings of our equity securities, which would cause dilution of our common stock;
•: sales of prospects generated by our exploration group, which would reduce future revenues from our exploration program;
•: additional sales of interests in our LNG projects, which would reduce future revenues from LNG terminal operations; and
•: arrangement of a business development loan from, or prepayment of terminal use fees by, prospective sellers or purchasers of LNG.

Our ability to raise additional capital will depend on our results of operations and the status of various capital and industry markets at the time such additional capital is sought. Accordingly, capital may not become available to us from any particular source or at all. Even if additional capital becomes available, it may not be on terms acceptable to us. Failure to obtain additional financing on acceptable terms may have a material adverse effect on our business, results of operations and financial condition.

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

Our oil and gas operations are subject to all of the risks and hazards typically associated with the exploration for, and the development and production of, oil and gas. In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could seriously harm our business, results of operations and financial condition.

Risks in drilling operations include cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. Our activities are also subject to perils specific to marine operations, such as capsizing, collision and damage or loss from severe weather. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.

In the event we complete LNG receiving terminals, the operations of such facilities will be subject to the inherent risks normally associated with those operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damage to persons and property. In addition, our operations face possible risks associated with acts of aggression on our assets. If any of these events were to occur, we could suffer substantial losses. We will maintain insurance against these types of risks to the extent and in the amounts that we believe are reasonable. Our financial condition and results of operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

Existing and future U.S. governmental regulation, taxation and price controls could seriously harm us.

Oil and gas operations are subject to extensive federal, state and local laws and regulations that regulate the discharge of materials into the environment or otherwise relate to the protection of the environment.

Failure to comply with such rules and regulations can result in substantial penalties and may harm us. Present, as well as future, legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. In most areas where we plan to conduct activities, there are statutory provisions regulating the production of oil and natural gas which may restrict the rate of production and adversely affect revenues. We plan to acquire oil and gas leases in the Gulf of Mexico, which, if acquired, would be granted by the federal government and administered by the U.S. Department of Interior Minerals Management Service. This department strictly regulates the exploration, development and production of oil and gas reserves in the Gulf of Mexico. Such regulations could seriously harm our operations in the Gulf of Mexico. The federal government regulates the interstate transportation of oil and natural gas, through the Federal Energy Regulatory Commission, or FERC. The FERC has in the past regulated the prices at which oil and

gas could be sold. Federal reenactment of price controls or increased regulation of the transport of oil and natural gas could seriously harm us.

Our operations are also subject to extensive federal, state and local laws and regulations governing the discharge of oil and hazardous materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment or wastes that can be disposed of in connection with drilling and production activities, prohibit drilling activities on certain lands lying within wetlands or other protected areas and impose substantial liabilities for pollution or releases of hazardous substances resulting from drilling and production operations. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. Moreover, state and federal environmental laws and regulations may become more stringent.

Federal laws and regulations such as the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Clean Air Act, or CAA, the Oil Pollution Act of 1990, or OPA, and the Clean Water Act, or CWA, and analogous state laws have continually imposed increasingly strict requirements for water and air pollution control, solid waste management and strict financial responsibility and remedial response obligations relating to oil spill protection. The cost of complying with such environmental legislation could have a general harmful effect on our operations.

In addition, the U.S. Department of Transportation through its Office of Pipeline Safety has regulations that govern all aspects of the design, construction, operation and maintenance of pipeline and LNG facilities. The Natural Gas Pipeline Safety Act ensures the integrity of pipeline systems by requiring periodic inspection of pipeline facilities and repair of any defects discovered in the inspection process.

Existing environmental laws and regulations may be revised or new laws and regulations may be adopted or become applicable to us. Revised or additional laws and regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from insurance or our customers, could have a material adverse effect on our business, financial condition or results of operations.

Some of our economic value is derived from our ownership interest in Gryphon, over which we exercise no day-to-day control.

We own 100% of the outstanding common stock of Gryphon (9.3% effective ownership after giving effect to the potential conversion of Gryphon's preferred stock) and some of our value is derived from this investment. We do not exercise control over Gryphon and therefore do not have the ability to effect a change of control of Gryphon. Accordingly, Gryphon's management team could make business decisions without our consent that could impair the economic value of our investment in Gryphon.

We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding

or trading in securities. A company may be deemed to be an investment company if it owns investment securities with a value exceeding 40% of the value of its total assets (excluding government securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own a minority equity interest in certain entities that could be counted as investment securities. If the value of our minority interests in these entities exceeds 40% of the value of our total assets (excluding government securities and cash items), we could be considered an investment company in the future if we do not obtain an exemption or qualify for a safe harbor. As a result, fluctuations in the value, or the income and revenues attributable to us from our ownership of interests in companies we do not control could cause us to be deemed an investment company. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy. We may have to take actions, including buying, refraining from buying, selling or refraining from selling securities or other assets, contrary to what we would otherwise deem to be in our best interest in order to continue to avoid registration under the Investment Company Act.

Terrorist attacks and continued hostilities in the Middle East or other sustained military campaigns may adversely impact our business.

The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. The long-term impact that terrorist attacks and the threat of terrorist attacks may have on our business is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may adversely impact our business in unpredictable ways.

The concentration of our customers in the energy industry could increase our exposure to credit risk, which could result in losses.

The concentration of our customers in the energy industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by prolonged changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables. We maintain reserves for credit losses and, generally, actual losses have been consistent with our expectations.

Use of proceeds

Unless otherwise specified in an accompanying prospectus supplement, we expect to use the net proceeds from the sale of the securities offered by this prospectus to fund:

•: expenditures related to development of our LNG receiving terminal sites;
•: expenditures related to oil and gas exploration activities;
•: working capital needs; and
•: expenditures related to general corporate purposes.

The actual application of proceeds from the sale of any particular tranche of securities issued hereunder will be described in the applicable prospectus supplement relating to such tranche of securities. We may invest funds not required immediately for these purposes in marketable securities and short-term investments. The precise amount and timing of the application of these proceeds will depend upon our funding requirements and the availability and cost of other funds.

Ratios of earnings to fixed charges

The following table sets forth our ratios of earnings to fixed charges on a consolidated basis for the periods shown. You should read these ratios of earnings to fixed charges in connection with our consolidated financial statements, including the notes to those statements, incorporated by reference into this prospectus.

	Years ended December 31,

	Years ended December 31,										Period ended June 30, 2004
	1999		2000		2001		2002		2003		Period ended June 30, 2004

Ratio of earnings to fixed charges	(4.01	)	(0.29	)	(48.82	)	(111.65	)	(18.21	)	(805.85	)

From its inception through June 30, 2004, the Company has reported losses, thus its earnings have been inadequate to cover fixed charges. The coverage deficiency was $2,168,985 in 1999, $1,508,430 in 2000, $8,856,884 in 2001, $3,405,200 in 2002, $851,006 in 2003, and $9,795,137 during the period from January 1, 2004 through June 30, 2004.

The ratios were computed by dividing earnings by fixed charges. For this purpose, "earnings" represent the aggregate of (a) pre-tax income from continuing operations before adjustment for minority interests in consolidated subsidiaries or income or loss from equity investees, (b) fixed charges, (c) amortization of capitalized interest, (d) distributed income of equity investees and (e) our share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges, net of (a) interest capitalized and (b) the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges. "Fixed charges" represent the sum of (a) interest expensed and capitalized, (b) amortized premiums, discounts and capitalized expenses related to indebtedness and (c) an estimate of the interest within rental expense.

Description of capital stock

General

The following is a summary of the key terms and provisions of our capital stock. You should refer to the applicable provisions of our amended and restated certificate of incorporation our amended and restated by-laws, the Delaware General Corporation Law and the documents that we have incorporated by reference for a complete statement of the terms and rights of our capital stock.

As of the date of this prospectus, we are authorized to issue up to 40,000,000 shares of common stock, par value $0.003 per share, and up to 5,000,000 shares of preferred stock, par value $0.0001 per share. As of August 30, 2004, we had 19,264,419 shares of common stock and no shares of preferred stock issued and outstanding.

Common stock

All of the outstanding shares of common stock are, and the common stock offered by any prospectus supplement will be, validly issued, fully paid and nonassessable upon issuance against full payment of the purchase price. Each share of common stock has an equal and ratable right to receive dividends when, as and if declared by the board of directors out of assets legally available therefor and subject to the dividend obligations to the holders of any preferred stock then outstanding.

In the event of our liquidation, dissolution or winding up, the holders of common stock are entitled to share equally and ratably in the assets available for distribution after payment of all liabilities, and subject to any prior rights of any holders of preferred stock that at the time may be outstanding.

The holders of common stock have no preemptive, subscription or conversion rights, and are not subject to further calls or assessments of Cheniere. There are no redemption or sinking fund provisions applicable to the common stock. Each share of common stock is entitled to one vote in the election of directors and on all other matters submitted to a vote of stockholders. Holders of common stock have no right to cumulate their votes in the election of directors, such that the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election.

The registrar and transfer agent for our common stock is U.S. Stock Transfer Corp., Glendale, California.

Preferred stock

Shares of preferred stock may be issued from time to time in one or more series and the board of directors, without further approval of the stockholders, is authorized to fix the dividend rates and terms, conversion rights, voting rights, redemption rights and terms, liquidation preferences and any other rights, preferences, privileges and restrictions applicable to each series of preferred stock. The purpose of authorizing the board of directors to determine such rights, preferences, privileges and restrictions is to allow such determinations to be made by the board of directors instead of the stockholders and to avoid the expense of, and eliminate delays associated with, a stockholder vote on specific issues.

Undesignated preferred stock may enable our board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and to thereby protect the continuity of our management. As a result, the issuance of shares of a series of preferred stock may discourage bids for our common stock or may otherwise adversely affect the market price of our common stock or any other series of our preferred stock. The issuance of shares of preferred stock may also adversely affect the rights of the holders of our common stock. For example, any preferred stock issued will rank prior to our common stock as to dividend rights and liquidation preference, and may have full or limited voting rights and may be convertible into shares of common stock or other securities.

The following description of the terms of the preferred stock sets forth some of the general terms and provisions of our authorized preferred stock. If we offer preferred stock under this prospectus, the terms may include the following:

•: the number of shares of each such series and the designation thereof;
•: the par value of shares of each such series;
•: the annual rate or amount of dividends, if any, payable on shares of each such series (which dividends would be payable in preference to any dividends on common stock), whether such dividends shall be cumulative or non-cumulative and the conditions upon which and/or the date when such dividends shall be payable;
•: whether the shares of each such series shall be redeemable and, if so, the terms and conditions of such redemption, including the time or times when and the price or prices at which shares of each such series may be redeemed;
•: the amount, if any, payable on shares of each such series in the event of liquidation, dissolution or winding up of the affairs of the Company;
•: whether the shares of each such series shall be convertible into or exchangeable for shares of any other class, or any series of the same or any other class, and, if so, the terms and conditions thereof, including the price or prices or the rate or rates at which shares of each such series shall be so convertible or exchangeable, and the adjustment which shall be made, and the circumstances in which such adjustments shall be made, in such conversion or exchange prices or rates; and
•: whether the shares of each such series shall have any voting rights in addition to those prescribed by law and, if so, the terms and conditions of exercise of voting rights.

This description of the terms of the preferred stock is not complete and will be subject to and qualified by the certificate of designation relating to any applicable series of preferred stock.

Possible anti-takeover provisions

Our restated certificate of incorporation contains provisions that might be characterized as anti-takeover provisions. Such provisions may render more difficult possible takeover proposals to acquire control of Cheniere and make removal of our management more difficult.

Our restated certificate of incorporation authorizes a class of undesignated preferred stock consisting of 5,000,000 shares. Preferred stock may be issued from time to time in one or more

series, and our board of directors, without further approval of the stockholders, is authorized to fix the rights, preferences, privileges and restrictions applicable to each series of preferred stock. The purpose of authorizing the board of directors to determine such rights, preferences, privileges and restrictions is to allow such determinations to be made by the board of directors instead of the stockholders and to avoid the expense of, and eliminate delays associated with, a stockholder vote on specific issuances. The issuance of preferred stock, while providing flexibility in connection with possible acquisitions and other corporate purposes, could, among other things, adversely affect the voting power of the holders of common stock and, under some circumstances, make it more difficult for a third party to gain control of Cheniere.

Our restated certificate of incorporation requires the affirmative vote of the holders of at least 66²/3% of the voting power of all of the shares of the corporation entitled to vote in order to amend or repeal our amended and restated by laws or to amend or repeal provisions of our restated certificate of incorporation relating to the division of the board of directors into three classes, stockholders' action by written consent, special meetings of the stockholders and amending or repealing our amended and restated bylaws.

Our restated certificate of incorporation and amended and restated by-laws provide that our board of directors shall be divided into three classes as nearly as equal in number as possible, with terms of office of one class of directors expiring each year, resulting in each class serving a staggered three-year term. Although dividing the directors into three classes enhances the likelihood of continuity and stability in the policies formulated by the board of directors, a staggered board significantly extends the time required to make any change in control of our board of directors and will tend to discourage any hostile takeover bid for us.

When there is a classified board of directors, the Delaware General Corporation Law provides that stockholders may remove directors only for cause, unless a company's certificate of incorporation otherwise provides. Our restated certificate of incorporation and amended and restated by-laws do not permit the removal of directors other than for cause. Such requirement may deter third parties from making a tender offer or acquiring our common stock through open market purchases in order to obtain control of us because they could not use their acquired voting power to remove existing directors.

Our restated certificate of incorporation and amended and restated by-laws provide that special meetings of our stockholders may be called only by our board of directors, the vice chairman of the board of directors, the president or the secretary. Stockholders are prohibited from calling special meetings. Eliminating the ability of stockholders to call a special meeting may result in delaying expensive proxy contests until our annual stockholders meeting, which might impact a person's decision to purchase our voting securities in an attempt to cause a change in control of Cheniere.

Our restated certificate of incorporation and amended and restated by-laws provide that stockholders may take action only at an annual or special meeting of the stockholders. Stockholders may not act by written consent. Eliminating the ability for stockholders to act by written consent could lengthen the amount of time required to take stockholder actions, which will ensure that stockholders will have sufficient time to weigh the arguments presented by both sides in connection with any contested stockholder vote, thereby potentially discouraging, delaying or preventing a change in control of Cheniere.

Although Section 214 of the Delaware General Corporation Law provides that a corporation's certificate of incorporation may provide for cumulative voting for directors, our restated certificate of incorporation does not provide for cumulative voting. As a result, the holders of a majority of the votes of the outstanding shares of our common stock have the ability to elect all of the directors being elected at any annual meeting of stockholders.

Under the business combination statute of the Delaware General Corporation Law, a corporation is generally restricted from engaging in a business combination with an interested stockholder for a three-year period following the time the stockholder became an interested stockholder. An interested stockholder is defined as a stockholder who, together with its affiliates or associates, owns, or who is an affiliate or associate of the corporation and within the prior three-year period did own, 15% or more of the corporation's voting stock. This restriction applies unless:

•: prior to the time the stockholder became an interested stockholder, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;
•: the interested stockholder owned at least 85% of the voting stock of the corporation upon completion of the transaction which resulted in the stockholder becoming an interested stockholder (excluding stock held by the company's directors who are also officers and by the company's employee stock plans, if any, that do not provide employees with the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer); or
•: at or subsequent to the time the stockholder became an interested stockholder, the business combination was approved by the board of directors of the corporation and authorized by the affirmative vote, at an annual or special meeting, and not by written consent, of at least 66²/3% of the outstanding voting shares of the corporation, excluding shares held by that interested stockholder.

A business combination generally includes:

•: mergers, consolidations and sales or other dispositions of 10% or more of the assets of a corporation to or with an interested stockholder;
•: transactions resulting in the issuance or transfer to an interested stockholder of any capital stock of the corporation or its subsidiaries, subject to certain exceptions;
•: transactions having the effect of increasing the proportionate share of the interested stockholder in the capital stock of the corporation or its subsidiaries, subject to certain exceptions; and
•: other transactions resulting in a disproportionate financial benefit to an interested stockholder.

The provisions of the Delaware business combination statute do not apply to a corporation if, subject to certain requirements specified in Section 203(b) of the Delaware General Corporation Law, the certificate of incorporation or by-laws of the corporation contain a provision expressly electing not to be governed by the provisions of the statute or the corporation does not have voting stock listed on a national securities exchange, authorized for quotation on the Nasdaq Stock Market or held of record by more than 2,000 stockholders.

We have not adopted any provision in our restated certificate of incorporation or amended and restated by-laws electing not to be governed by the Delaware business combination statute. As a result, the statute is applicable to business combinations involving Cheniere.

Description of debt securities

Any debt securities we offer under a prospectus supplement will be direct, unsecured general obligations. The debt securities will be either senior unsecured debt securities or senior subordinated debt securities. The debt securities will be issued under one or more separate indentures between us and a banking or financial institution, as trustee. Senior unsecured debt securities will be issued under a senior unsecured indenture and senior subordinated debt securities will be issued under a senior subordinated indenture. Together the senior unsecured indenture and the senior subordinated indenture are called "indentures."

We have summarized selected provisions of the indentures below. The following summary is a description of the material provisions of the indentures. It does not restate those agreements in their entirety. We urge you to read each of the indentures because each one, and not this description, defines the rights of holders of debt securities. A form of senior unsecured indenture and a form of senior subordinated indenture have been filed as exhibits to the registration statement of which this prospectus is a part.

General

The debt securities will be our direct, unsecured general obligations. The senior unsecured debt securities will rank equally with all of our other senior and unsubordinated debt. The senior subordinated debt securities will have a junior position to all of our senior debt.

A substantial portion of our assets are held by our operating subsidiaries, Cheniere LNG, Inc., Cheniere LNG Services, Inc., Cheniere Energy Operating Co., Inc. and Cheniere-Gryphon Management, Inc. With respect to these assets, holders of senior unsecured debt securities that are not guaranteed by our operating subsidiaries and holders of senior subordinated debt securities will have a position junior to the prior claims of creditors of these subsidiaries, including trade creditors, debtholders, secured creditors, taxing authorities and guarantee holders, and any preferred stockholders, except to the extent that we may ourself be a creditor with recognized claims against any subsidiary. Our ability to pay the principal, premium, if any, and interest on any debt securities is, to a large extent, dependent upon the payment to us by our subsidiaries of dividends, debt principal and interest or other charges.

The following description sets forth the general terms and provisions that could apply to debt securities that we may offer to sell. A prospectus supplement and an indenture relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:

•: The title and type of the debt securities;
•: The total principal amount of the debt securities;
•: The percentage of the principal amount at which the debt securities will be issued and any payments due if the maturity of the debt securities is accelerated;
•: The dates on which the principal of the debt securities will be payable;

•: The interest rate which the debt securities will bear and the interest payment dates for the debt securities;
•: Any conversion or exchange features;
•: Any optional redemption periods;
•: Any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem some or all of the debt securities;
•: Any provisions granting special rights to holders when a specified event occurs;
•: Any changes to or additional events of default or covenants;
•: Any special tax implications of the debt securities, including provisions for original issue discount securities, if offered; and
•: Any other terms of the debt securities.

None of the indentures will limit the amount of debt securities that may be issued. Each indenture will allow debt securities to be issued up to the principal amount that may be authorized by us and may be in any currency or currency unit designated by us.

Debt securities of a series may be issued in registered, coupon or global form.

Denominations

The prospectus supplement for each issuance of debt securities will state that the securities will be issued in registered form of $1,000 each or integral multiples thereof.

Subordination

Under a senior subordinated indenture, payment of the principal, interest and any premium on the senior subordinated debt securities will generally be subordinated and junior in right of payment to the prior payment in full of all senior debt (as defined in the senior subordinated indenture). A senior subordinated indenture will provide that no payment of principal, interest and any premium on the senior subordinated debt securities may be made in the event we fail to pay the principal, interest, any premium on any senior debt when due or if another default occurs that results in acceleration of senior debt. In addition, in the event of any distribution of our assets upon our dissolution, liquidation or reorganization (including in a bankruptcy, insolvency or similar proceeding), holders of senior debt will be entitled to payment in full before any payment or distribution of our assets is made to holders of senior subordinated debt securities.

A senior subordinated indenture will not limit the amount of senior debt that we may incur.

Mergers and sale of assets

Each indenture will provide that we may not consolidate with or merge into any other person or sell, convey, transfer or lease all or substantially all of our properties and assets (on a consolidated basis) to another person, unless:

•: the successor person assumes all of our obligations under the indentures; and
•: we or the successor person will not immediately be in default under the indentures.

Upon the assumption of our obligations by a successor, we will be discharged from all obligations under the indentures.

Modification of indentures

Each indenture will provide that our rights and obligations and the rights of the holders may be modified with the consent of the holders of a majority in aggregate principal amount of the outstanding debt securities of each series affected by the modification. No modification of the principal or interest payment terms, and no modification reducing the percentage required for modifications, will be effective against any holder without its consent.

Events of default

"Event of default," when used in an indenture, will mean any of the following:

•: failure to pay the principal of, or any premium on, any debt security when due;
•: failure to deposit any sinking fund payment when due;
•: failure to pay interest on any debt security for 30 days;
•: failure to perform any covenant set forth in the covenants section of the indenture that continues for 90 days after we are given written notice;
•: failure to perform any other covenant in the indenture that continues for 180 days after we are given written notice;
•: certain events in bankruptcy, insolvency or reorganization of us; or
•: any other event of default included in a supplemental indenture or any officer's certificate setting forth additional terms of the debt security.

An event of default for a particular series of debt securities does not necessarily constitute an event of default for any other series of debt securities issued under an indenture. The trustee may withhold notice to the holders of debt securities of any default (except in the payment of principal or interest) if it considers the withholding of notice to be in the best interests of the holders.

If an event of default for any series of debt securities occurs and continues, the trustee or the holders of a specified percentage in aggregate principal amount of the debt securities of the series may declare the entire principal of all the debt securities of that series to be due and payable immediately. If this happens, subject to certain conditions, the holders of a specified percentage of the aggregate principal amount of the debt securities of that series can void the declaration.

Other than its duties in case of a default, a trustee is not obligated to exercise any of its rights or powers under any indenture at the request, order or direction of any holders, unless the holders offer the trustee reasonable indemnity. If they provide this reasonable indemnification, the holders of a majority in principal amount outstanding of any series of debt securities may direct the time, method and place of conducting any proceeding or any remedy available to the trustee, or exercising any power conferred upon the trustee, for any series of debt securities.

Covenants

Under the indentures, we:

•: will pay the principal of, interest and any premium on, the debt securities when due;
•: will maintain a place of payment;
•: will deliver a report to the trustee at the end of each fiscal year reviewing our obligations under the indentures; and
•: will deposit sufficient funds with any paying agent on or before the due date for any principal, interest or premium.

In addition, under a senior unsecured indenture, we:

•: will not, nor will we permit our operating subsidiaries to, create or incur any liens upon any principal property unless specified conditions are met, subject to certain exceptions; and
•: will not, nor will we permit our operating subsidiaries to, enter into any sale-and-leaseback transaction unless certain conditions are met, subject to certain exceptions.

Subsidiary guarantees

If the applicable prospectus supplement relating to a series of our senior unsecured debt securities provides that those senior unsecured debt securities will have the benefit of a guarantee by any or all of our operating subsidiaries (Cheniere LNG Services, Inc., Cheniere LNG, Inc., Cheniere Energy Operating Co., Inc. and Cheniere-Gryphon Management, Inc.) payment of the principal, premium, if any, and interest on those senior unsecured debt securities will be unconditionally guaranteed on an unsecured, unsubordinated basis by such subsidiary or subsidiaries. The guarantee of senior unsecured debt securities will rank equally in right of payment with all of the unsecured and unsubordinated indebtedness of such subsidiary or subsidiaries.

If the applicable prospectus supplement relating to a series of our senior subordinated debt securities provides that those senior subordinated debt securities will have the benefit of a guarantee by any or all of our operating subsidiaries, payment of the principal, premium, if any, and interest on those senior subordinated debt securities will be unconditionally guaranteed on an unsecured, subordinated basis by such subsidiary or subsidiaries. The guarantee of the senior subordinated debt securities will be subordinated in right of payment to all of such subsidiary's or subsidiaries' existing and future senior indebtedness (as defined in the related prospectus supplement), including any guarantee of the senior unsecured debt

securities, to the same extent and in the same manner as the senior subordinated debt securities are subordinated to our senior indebtedness (as defined in the related prospectus supplement). See "—Subordination" above.

The obligations of our operating subsidiaries under any such guarantee will be limited as necessary to prevent the guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law.

Payment and transfer

Principal, interest and any premium on fully registered securities will be paid at designated places. Payment will be made by check mailed to the persons in whose names the debt securities are registered on days specified in the indentures or any prospectus supplement. Debt securities payments in other forms will be paid at a place designated by us and specified in a prospectus supplement.

Fully registered securities may be transferred or exchanged at the corporation trust office of the trustee or at any other office or agency maintained by us for such purposes, without the payment of any service charge except for any tax or governmental charge.

Global securities

The debt securities of a series may be issued in whole or in part in the form of one or more global certificates that we will deposit with a depository identified in the applicable prospectus supplement. Unless and until it is exchanged in whole or in part for the individual debt securities it represents, a global security may not be transferred except as a whole:

•: by the applicable depositary to a nominee of the depositary;
•: by any nominee to the depositary itself or another nominee; or
•: by the depositary or any nominee to a successor depositary or any nominee of the successor.

We will describe the specific terms of the depositary arrangement with respect to a series of debt securities in the applicable prospectus supplement. We anticipate that the following provisions will generally apply to depository arrangements.

When we issue a global security in registered form, the depositary for the global security or its nominee will credit, on its book-entry registration and transfer system, the respective principal amounts of the individual debt securities represented by that global security to the accounts of persons that have accounts with the depositary ("participants"). Those accounts will be designated by the dealers, underwriters or agents with respect to the underlying debt securities or by us if those debt securities are offered and sold directly by us. Ownership of beneficial interests in a global security will be limited to participants or persons that may hold interests through participants. For interests of participants, ownership of beneficial interests in the global security will be shown on records maintained by the applicable depositary or its nominee. For interests of persons other than participants, that ownership information will be shown on the records of participants. Transfer of that ownership will be effected only through those records. The laws of some states require that certain purchasers of securities take physical

delivery of securities in definitive form. These limits and laws may impair our ability to transfer beneficial interests in a global security.

As long as the depositary for a global security, or its nominee, is the registered owner of that global security, the depositary or nominee will be considered the sole owner or holder of the debt securities represented by the global security for all purposes under the applicable indenture. Except as provided below, owners of beneficial interests in a global security:

•: will not be entitled to have any of the underlying debt securities registered in their names;
•: will not receive or be entitled to receive physical delivery of any of the underlying debt securities in definitive form; and
•: will not be considered the owners or holders under the indenture relating to those debt securities.

Payments of principal of, any premium on and any interest on individual debt securities represented by a global security registered in the name of a depositary or its nominee will be made to the depositary or its nominee as the registered owner of the global security representing such debt securities. Neither we, the trustee for the debt securities, any paying agent nor the registrar for the debt securities will be responsible for any aspect of the records relating to or payments made by the depositary or any participants on account of beneficial interests in the global security.

We expect that the depositary or its nominee, upon receipt of any payment of principal, any premium or interest relating to a global security representing any series of debt securities, immediately will credit participants' accounts with the payments. Those payments will be credited in amounts proportional to the respective beneficial interests of the participants in the principal amount of the global security as shown on the records of the depositary or its nominee. We also expect that payments by participants to owners of beneficial interests in the global security held through those participants will be governed by standing instructions and customary practices. This is now the case with securities held for the accounts of customers registered in "street name." Those payments will be the sole responsibility of those participants.

If the depositary for a series of debt securities is at any time unwilling, unable or ineligible to continue as depositary and we do not appoint a successor depositary within 90 days, we will issue individual debt securities of that series in exchange for the global security or securities representing that series. In addition, we may at any time in our sole discretion determine not to have any debt securities of a series represented by one or more global securities. In that event, we will issue individual debt securities of that series in exchange for the global security or securities. Further, if we specify, an owner of a beneficial interest in a global security may, on terms acceptable to us, the trustee and the applicable depositary, receive individual debt securities of that series in exchange for those beneficial interests. The foregoing is subject to any limitations described in the applicable prospectus supplement. In any such instance, the owner of the beneficial interest will be entitled to physical delivery of individual debt securities equal in principal amount to the beneficial interest and to have the debt securities registered in its name. Those individual debt securities will be issued in any authorized denominations.

Defeasance

We will be discharged from our obligations on the debt securities of any series at any time if we deposit with the trustee sufficient cash or government securities to pay the principal, interest, any premium and any other sums due to the stated maturity date or a redemption date of the debt securities of the series. If this happens, the holders of the debt securities of the series will not be entitled to the benefits of the indenture except for registration of transfer and exchange of debt securities and replacement of lost, stolen or mutilated debt securities.

Under federal income tax law as of the date of this prospectus, a discharge may be treated as an exchange of the related debt securities. Each holder might be required to recognize gain or loss equal to the difference between the holder's cost or other tax basis for the debt securities and the value of the holder's interest in the trust. Holders might be required to include as income a different amount than would be includable without the discharge. Prospective investors are urged to consult their own tax advisers as to the consequences of a discharge, including the applicability and effect of tax laws other than the federal income tax law.

Governing law

Each indenture and the debt securities will be governed by and construed in accordance with the laws of the State of New York.

Notices

Notices to holders of debt securities will be given by mail to the addresses of such holders as they appear in the security register for such debt securities.

No personal liability of officers, directors, employees or stockholders

No officer, director, employee or stockholder, as such, of ours or any of our affiliates shall have any personal liability in respect of our obligations under any indenture or the debt securities by reason of his, her or its status as such.

Information concerning the trustee

A banking or financial institution will be the trustee under the indentures. A successor trustee may be appointed in accordance with the terms of the indentures.

The indentures and the provisions of the Trust Indenture Act of 1939, or Trust Indenture Act, incorporated by reference therein, will contain certain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; provided, however, that if it acquires any conflicting interest (within the meaning of the Trust Indenture Act) it must eliminate such conflicting interest or resign.

A single banking or financial institution may act as trustee with respect to both the senior subordinated indenture and the senior unsecured indenture. If this occurs, and should a default occur with respect to either the senior subordinated debt securities or the senior unsecured

debt securities, such banking or financial institution, would be required to resign as trustee under one of the indentures within 90 days of such default, pursuant to the Trust Indenture Act, unless such default were cured, duly waived or otherwise eliminated.

Description of warrants

We may issue warrants to purchase common stock, preferred stock, debt securities or units. Warrants may be issued independently or together with any other securities and may be attached to, or separate from, such securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a warrant agent. The terms of any warrants to be issued and a description of the material provisions of the applicable warrant agreement will be set forth in the applicable prospectus supplement.

The applicable prospectus supplement will specify the following terms of any warrants in respect of which this prospectus is being delivered:

•: the title of such warrants;
•: the aggregate number of such warrants;
•: the price or prices at which such warrants will be issued;
•: the securities purchasable upon exercise of such warrants;
•: the price at which, and the currency or currencies in which the securities purchasable upon exercise of, such warrants may be purchased;
•: the date on which the right to exercise such warrants shall commence and the date on which such right shall expire;
•: if applicable, the minimum or maximum amount of such warrants which may be exercised at any one time;
•: if applicable, the designation and terms of the securities with which such warrants are issued and the number of such warrants issued with each such security;
•: if applicable, the date on and after which such warrants and the related securities will be separately transferable;
•: information with respect to book-entry procedures, if any;
•: if applicable, a discussion of any material U.S. federal income tax considerations; and
•: any other terms of such warrants, including terms, procedures and limitations relating to the exchange and exercise of such warrants.

As of August 30, 2004, we have issued and outstanding warrants to purchase 862,917 shares of common stock. The warrants do not confer upon holders thereof any voting or other rights of stockholders.

Description of units

As specified in the applicable prospectus supplement, we may issue units consisting of one or more debt securities, shares of common stock, shares of preferred stock or warrants or any combination of such securities.

The applicable prospectus supplement will specify the following terms of any units in respect of which this prospectus is being delivered:

•: the terms of the units and of any of the debt securities, common stock, preferred stock and warrants comprising the units, including whether and under what circumstances the securities comprising the units may be traded separately;
•: a description of the terms of any unit agreement governing the units; and
•: a description of the provisions for the payment, settlement, transfer or exchange of the units.

Plan of distribution

We may sell the securities through agents, underwriters or dealers, or directly to one or more purchasers without using underwriters or agents.

We may designate agents to solicit offers to purchase our securities. We will name any agent involved in offering or selling our securities, and any commissions that we will pay to the agent, in the applicable prospectus supplement. Unless we indicate otherwise in our prospectus supplement, our agents will act on a best efforts basis for the period of their appointment.

If underwriters are used in the sale, the securities will be acquired by the underwriters for their own account. The underwriters may resell the securities in one or more transactions (including block transactions), at negotiated prices, at a fixed public offering price or at varying prices determined at the time of sale. We will include the names of the managing underwriter(s), as well as any other underwriters, and the terms of the transaction, including the compensation the underwriters and dealers will receive, in our prospectus supplement. If we use an underwriter, we will execute an underwriting agreement with the underwriter(s) at the time that we reach an agreement for the sale of our securities. The obligations of the underwriters to purchase the securities will be subject to certain conditions contained in the underwriting agreement. The underwriters will be obligated to purchase all the securities of the series offered if any of the securities are purchased. Any public offering price and any discounts or concessions allowed or re-allowed or paid to dealers may be changed from time to time. The underwriters will use a prospectus supplement to sell our securities.

If we use a dealer, we, as principal, will sell our securities to the dealer. The dealer will then sell our securities to the public at varying prices that the dealer will determine at the time it sells our securities. We will include the name of the dealer and the terms of our transactions with the dealer in the applicable prospectus supplement.

We may directly solicit offers to purchase our securities, and we may directly sell our securities to institutional or other investors. In this case, no underwriters or agents would be involved. We will describe the terms of our direct sales in the applicable prospectus supplement.

Underwriters, dealers and agents that participate in the distribution of the securities may be underwriters as defined in the Securities Act and any discounts or commissions received by them from us and any profit on their resale of the securities may be treated as underwriting discounts and commissions under the Securities Act. In connection with the sale of the securities offered by this prospectus, underwriters may receive compensation from us or from the purchasers of the securities, for whom they may act as agents, in the form of discounts, concessions or commissions, which will not exceed 8% of the proceeds from the sale of the securities. Any underwriters, dealers or agents will be identified and their compensation described in the applicable prospectus supplement. We may have agreements with the underwriters, dealers and agents to indemnify them against certain civil liabilities, including liabilities under the Securities Act, or to contribute with respect to payments which the underwriters, dealers or agents may be required to make. Underwriters, dealers and agents may engage in transactions with, or perform services for, us or our subsidiaries in the ordinary course of their business.

Unless otherwise specified in the applicable prospectus supplement, all securities offered under this prospectus will be a new issue of securities with no established trading market, other than the common stock, which is currently listed and traded on the American Stock Exchange. We may elect to list any other class or series of securities on a national securities exchange or a foreign securities exchange but are not obligated to do so. Any common stock sold by this prospectus will be listed for trading on the American Stock Exchange subject to official notice of issuance. We cannot give you any assurance as to the liquidity of the trading markets for any of the securities.

Any underwriter to whom securities are sold by us for public offering and sale may engage in over-allotment transactions, stabilizing transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act. Over-allotment transactions involve sales by the underwriters of the securities in excess of the offering size, which creates a syndicate short position. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the securities in the open market after the distribution has been completed in order to cover syndicate short positions. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the securities originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. These activities may cause the price of the securities to be higher than it would otherwise be. The underwriters will not be obligated to engage in any of the aforementioned transactions and may discontinue such transactions at any time without notice.

Legal matters

The validity of the securities will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Any underwriter will be advised about other issues relating to any offering by its own legal counsel.

Experts

The consolidated financial statements of Cheniere Energy, Inc. at December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003 appearing in our Annual Report on Form 10 K/A for the fiscal year ended December 31, 2003, which was filed with the SEC on July 20, 2004, have been audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP (formerly Mann Frankfort Stein & Lipp CPAs, L.L.P.), independent registered public accounting firm, as set forth in their report thereon included therein and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

On October 22, 2002, we filed a Current Report on Form 8-K announcing that we had engaged Mann Frankfort Stein & Lipp CPAs, L.L.P. as independent auditors for the fiscal year ending December 31, 2002, replacing PricewaterhouseCoopers LLP. The decision to change independent public accountants was not the result of any disagreement with PricewaterhouseCoopers LLP on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements if not resolved to the satisfaction of PricewaterhouseCoopers LLP, would have caused them to make a reference thereto in their report on the financial statements of Cheniere Energy, Inc. for the two years ended December 31, 2001 and the subsequent interim period through such dismissal.

The information incorporated by reference into this prospectus regarding our estimated proved reserves are based on the reports generated by our independent petroleum engineers, Sharp Petroleum Engineering, Inc. in 2003 and Ryder Scott Company in 2001 and substantially, but not wholly, based on the report generated by Ryder Scott Company in 2002.

Interests of named experts and counsel

The validity of the shares of common stock registered in this Registration Statement on Form S-3 has been passed upon for the Registrant by Andrews Kurth LLP whose opinion is attached to the Registration Statement as Exhibit 5.1. Geoffrey K. Walker, a partner in Andrews Kurth LLP, owns 5,000 shares of common stock of the Registrant.

5,000,000 shares

Common stock

Prospectus Supplement
(To Prospectus dated September 10, 2004)

JPMorgan
Merrill Lynch & Co.		Petrie Parkman & Co.
Pritchard Capital Partners LLC

December 2, 2004

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not authorized anyone to provide you with information different from that contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We are offering to sell, and seeking offers to buy, common stock only in jurisdictions where offers and sales are permitted. The information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus is accurate only as of the respective dates of this prospectus supplement and the accompanying prospectus, regardless of the time of delivery of this prospectus supplement and the accompanying prospectus or of any sale of our common stock.