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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2003

OR

For the transition period from                               to                              

Commission File No. 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 659-1361

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $66,180,000 as of June 30, 2003.

18,659,994 shares of the registrant’s Common Stock were outstanding as of February 29, 2004.

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

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CHENIERE ENERGY, INC.

Index to Form 10-K

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report 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 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, are forward-looking statements. These forward-looking statements are often 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 annual report.

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 16. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

Cheniere Energy, Inc., a Delaware corporation, is 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. The LNG receiving terminal business consists of receiving deliveries of LNG from LNG ships, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers. We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

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

On October 16, 2000, our stockholders approved a one-for-four reverse stock split. The reverse stock split became effective on October 18, 2000 and reduced our issued and outstanding shares from 43,989,572 shares to 10,997,393 shares. All historical share and per share data appearing in this document reflect the reverse stock split.

As used in this annual report, certain terms have the following meanings:

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Access to Public Filings

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website (located at www.cheniere.com), where we provide a link to the SEC’s website (at www.sec.gov). We make our website content available for informational purposes only. The website should not be relied upon for investment purposes.

General Development of Business

Cheniere Energy Operating Co., Inc. (“Cheniere Operating”) was incorporated in Delaware in February 1996 for the purpose of engaging in the oil and gas exploration business, initially on the Louisiana Gulf Coast. On July 3, 1996, Cheniere Operating underwent a reorganization whereby Bexy Communications, Inc., a publicly-held Delaware corporation (“Bexy”), received 100% of the outstanding shares of Cheniere Operating, and the former stockholders of Cheniere Operating received approximately 93% of the issued and outstanding Bexy shares. As a result of the share exchange, a change in control occurred. The transaction was accounted for as a recapitalization of Cheniere Operating. Bexy spun off its existing assets and liabilities to its original stockholders and changed its name to Cheniere Energy, Inc. Cheniere Operating became a wholly-owned subsidiary of Cheniere.

We have two reporting segments: one segment is the LNG Receiving Terminal Development business and the other is the Oil and Gas Exploration and Development business.

LNG Receiving Terminal Development

LNG is natural gas that has been reduced to a fraction of its volume through a sophisticated refrigeration process. The liquefaction of natural gas (into LNG) allows it to be shipped long distances comparatively safely and economically. Outside the U.S., utilization of LNG has grown dramatically. As of February 15, 2004, there

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were 70 liquefaction plants in 12 countries capable of producing 6.5 Tcfe of LNG per year and 43 terminals in 12 countries capable of importing and regasifying LNG. Yet in the U.S., due mainly to a historically abundant supply of natural gas, LNG has not been a major energy source. However, U.S. natural gas producers have recently had limited ability to increase supply, and costs of domestic natural gas exploration and production have increased. As a result, we believe that LNG will become a competitive supply alternative to domestic natural gas and other import alternatives. Assuming current construction costs of LNG-related facilities and tankers, we believe that LNG can be economically produced and delivered as natural gas into U.S. pipelines at a cost lower than $3.00 per Mmbtu.

In 2000, we undertook a feasibility study to assess the long-term natural gas markets in the U.S. and, in particular, the potential role of LNG in meeting a portion of the gas supply deficit anticipated to develop later in this decade. Based on that analysis, our management concluded that LNG would become an economically viable source of natural gas supply in the U.S. In 2001, we assembled an experienced LNG project development team and began a study to determine viable locations for LNG receiving terminals in the U.S. We have chosen sites along the Gulf Coast at which we may develop LNG receiving terminals. The Gulf Coast area offers several important advantages, including the following:

LNG Receiving Terminal Sites

Freeport LNG

An LNG receiving facility will be developed on Quintana Island near Freeport, Texas on a 233-acre tract of land and will be designed with regas capacity of 1.5 Bcf per day, one dock, and two storage tanks with an aggregate storage capacity of 6.7 Bcfe. The unloading dock will be able to handle 75,000 cm to greater than 200,000 cm LNG shipping vessels. From the terminal, natural gas will be transported through a 9.3-mile pipeline to Stratton Ridge, Texas, which is a major point of interconnection with the Texas intrastate gas pipeline system. The cost to construct the facility is currently estimated to be in excess of $500 million.

In June 2001, we acquired an option to lease acreage suitable for an LNG receiving terminal site near Freeport and funded the initial permitting expenses of the project. In connection with the acquisition of our option, we issued 500,000 shares of common stock valued at $1,150,000, or $2.30 per share, the closing price of our common stock on the date of the transaction, to the seller of the lease option. We also committed to issue an additional 750,000 shares of our common stock to the seller of the lease option at a later date, for which we received no additional consideration. These shares were issued in April 2003 at a value of $1,312,500, or $1.75 per share, the closing price of our common stock on the date of issuance. The seller of the lease option also obtained the right to receive a royalty payment on the gross quantities of gas processed through LNG terminals owned by Cheniere LNG, Inc., our wholly-owned subsidiary. The royalty is calculated based on $0.03 per Mcf on the quantities of gas processed through LNG terminals we own, subject to a maximum royalty of approximately $10,950,000 per year. In 2002, a long-term lease was secured, and at the closing of the sale of our interests in the site and project to Freeport LNG Development, L.P. (“Freeport LNG”), Freeport LNG assumed the obligation to pay the royalty with respect to gas processed and produced at the Freeport LNG facility.

In August 2002, we entered into an agreement with entities controlled by Michael S. Smith (“Smith”) to sell a 60% interest in the Freeport site and project. On February 27, 2003, we consummated the transaction by selling

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our interest in the site and project to Freeport LNG, in which we held a 40% limited partner interest. Smith holds a 60% limited partner interest in Freeport LNG. We recovered $1,740,426, in costs we had incurred on the project and received an additional $5,000,000 from Freeport LNG. For the funding of Freeport LNG project development costs, Smith also committed to contribute up to $9,000,000 and to allocate available proceeds from any sales of options or capacity reservations and/or proceeds from loans related to capacity reservations to these costs. In connection with the closing, we issued warrants to Smith to purchase 700,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years.

Effective March 1, 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company (“Contango”) for $2,333,333 payable over time, including the cancellation of our $750,000 short-term note payable. We also issued warrants to Contango to purchase 300,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG.

In June 2003, The Dow Chemical Company (“Dow”) signed an agreement with Freeport LNG for the potential long-term use of the facility. Under the agreement, Dow will have regas rights to as much as 500 Mmcf/d beginning with commercial start-up of the facility in 2007. On February 26, 2004, Freeport LNG and Dow entered into a twenty-year terminal use agreement (“TUA”). Under the terms of the TUA, Dow made a firm commitment to reserve regas capacity of 250 Mmcf/d and has until August 31, 2004 to exercise its option on the remaining 250 Mmcf/d.

On December 21, 2003, ConocoPhillips signed an agreement with Freeport LNG under which ConocoPhillips will participate in Freeport LNG’s receiving terminal. Pursuant to the agreement, ConocoPhillips will reserve one Bcf per day of regas capacity in the terminal for its use, obtain a 50% interest in the general partner of Freeport LNG, and provide a substantial majority of the financing to construct the facility, which is currently estimated to cost in excess of $500 million. The management of Freeport LNG will remain in place and will be responsible for all commercial activities and interfacing with customers for the remaining capacity in the facility. ConocoPhillips will be primarily responsible for managing the construction and operation of the facility. ConocoPhillips, as a user of the facility, will be required to pay its proportionate share of operating expenses and fuel costs, a throughput fee of $0.05 per Mcf, and all amounts necessary to amortize the construction funding. ConocoPhillips paid a nonrefundable capacity reservation fee of $10,000,000 to Freeport LNG in January 2004. The transaction is expected to close in the spring of 2004, subject to completion of remaining documentation and satisfaction of closing conditions.

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:

We believe that it is unlikely that we will have to contribute any additional capital funds.

The general partner of Freeport LNG is authorized to do all things necessary to obtain debt and/or 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, each limited partner that is an accredited investor has the right to participate in any such equity financing to the extent that enables such limited partner to maintain its percentage ownership interest in Freeport LNG.

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Approval of the Freeport LNG project from the Federal Energy Regulatory Commission (“FERC”) is expected in March or April of 2004, with all other necessary federal, state and local approvals shortly thereafter. The front-end engineering and design study for the Freeport LNG project was completed in January 2004. Construction is scheduled to begin in the second half of 2004, with commercial start-up expected in the second half of 2007.

Corpus Christi LNG and Sabine Pass LNG

We are currently developing two additional LNG receiving terminals: one near Corpus Christi, Texas and one near Sabine Pass, Louisiana. Each of these terminals will be designed with regas capacity of 2.6 Bcf per day, two docks, and three storage tanks with an aggregate storage capacity of 10.1 Bcfe. Each of these facilities will have two unloading docks that can handle 87,000 cm to 250,000 cm LNG shipping vessels. Each location will also have three dedicated tugboats. The cost to construct the Corpus Christi facility is currently estimated at approximately $450-$550 million, and the cost to construct the Sabine Pass facility is currently estimated at approximately $500-$600 million.

We formed Corpus Christi LNG, L.P. (“Corpus LNG”) in May 2003 to develop an LNG receiving terminal near Corpus Christi, Texas. Under the terms of the limited partnership agreement, 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 LNG. 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 $4,500,000 of Corpus LNG project expenses in exchange for its 33.3% limited partner interest. In January 2004, BPU LNG entered into an option agreement with Corpus LNG to acquire 100 Mmcf of natural gas per day regas capacity through the receiving terminal. We will manage the project through the general partner interest held by our wholly-owned subsidiary.

We recently formed Sabine Pass LNG, L.P. (“Sabine Pass LNG”) to develop an LNG receiving terminal near Sabine Pass, Louisiana. We currently plan to retain 100% of the ownership interest in Sabine Pass LNG. We intend to fund some of the development costs but plan to obtain additional equity or debt financing for this project. We have options on three tracts of land comprising 568 acres in Cameron Parish, Louisiana which collectively are suitable for the project site.

On December 22, 2003, we submitted to FERC applications for permits to build these LNG receiving facilities, as well as separate but concurrent permit applications for their related pipelines. See “Other Developments.” We have selected Bechtel Corporation to perform the engineering, procurement and construction for the facilities under a fixed price contract to be negotiated. The front end engineering design work for the terminals was completed by Black & Veatch Pritchard, Inc.

Other Developments

In addition to the sites discussed above for which we have submitted FERC applications, we are also evaluating other sites that we believe may be commercially feasible for developing LNG receiving terminals. These potential sites include locations in Brownsville, Texas and Mobile, Alabama for which we currently have lease options in place.

We have also begun to market natural gas pipeline capacity from the site of our proposed Sabine Pass and Corpus LNG receiving terminals. We plan to construct a 16-mile, 42-inch diameter natural gas pipeline from the site of our proposed Sabine Pass LNG receiving terminal, running easterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas pipelines in Southwest Louisiana. We also plan to construct a 24-mile, 48-inch diameter natural gas pipeline from the site of our proposed Corpus LNG receiving terminal, running northwesterly along a corridor that will allow for interconnection points with interstate and

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intrastate natural gas transmission pipelines in South Texas. The feasibility of constructing such pipelines will depend on market demand for natural gas from the respective terminals.

J & S Cheniere

Cheniere LNG Services, Inc. (“Cheniere LNG Services”), one of our wholly-owned subsidiaries, holds a minority interest in J & S Cheniere S.A. (“J&S Cheniere”), a Switzerland joint-stock company. The majority interest in J&S Cheniere is held by J & S Group S.A. (“J&S Group”), a Luxembourg corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Under a shareholders agreement, Cheniere LNG Services identifies and assists with LNG-related business opportunities that it determines are appropriate for J&S Cheniere. Cheniere LNG Services is not required to offer any particular business opportunities nor funding to J&S Cheniere. All financing of the 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 shareholders agreement gives Cheniere LNG Services the right to purchase additional shares up to a maximum of 50% of the outstanding shares of J&S Cheniere. The shareholders agreement also provides J&S Group the right to acquire all J&S Cheniere shares owned by us in the event we experience a change in control (defined in the shareholders 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, 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, J&S Cheniere has contracted to charter an LNG ship upon completion of its refurbishment in February 2004 for an 18-month period. In January 2004, J&S Cheniere signed a transportation agreement with Sonatrach, the national oil company of Algeria, to optimize the use of this LNG ship. During the six-month term of the agreement, the two companies will jointly operate the vessel and endeavor to find the most profitable routes for the vessel. The ship is anticipated to be used primarily as a trading vessel and not in connection with a specific project.

Cheniere LNG, Inc., one of our wholly-owned subsidiaries, and J&S Cheniere entered into an option agreement on December 23, 2003 under which J&S Cheniere has an option to purchase LNG storage tank capacity and regas capacity of up to 200 Mmcf/d in each of the Sabine Pass and Corpus Christi facilities. Following execution of the option agreement, $1,000,000 was paid by J&S Cheniere to Cheniere LNG, Inc. in January 2004. At December 31, 2003, we included the $1,000,000 in accounts receivable and the offset was recorded as deferred revenue, as the option fee is refundable if we do not receive FERC approval for at least one of the terminals or we do not proceed with the development of at least one of the terminals. Upon FERC approval and other related approvals and receipt of permits for each terminal, J&S Cheniere has 60 days to exercise its option at each terminal. The option agreement contemplates negotiation of a definitive TUA for each of the facilities, which will specify the terms and conditions of the purchase and sale of the capacity and related services.

Business Strategy

We believe that the long-term outlook for natural gas prices in the U.S. is one that will sustain prices at or above $3.00 per Mcf. We believe that such an environment will favor not only domestic exploration and production, but also LNG imports into the U.S. Our primary objective is to develop our LNG receiving terminal development business.

We have assembled a team of professionals with extensive experience in the LNG industry. We have researched the LNG opportunity, developed a plan to exploit the opportunity and initiated the process of identifying and securing sites for LNG receiving terminals as well as undertaking necessary regulatory and permitting work to advance these projects. In addition, we are marketing natural gas pipelines from the proposed

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sites of our Corpus LNG and Sabine Pass LNG receiving terminals. Most of our resources and most of the time and attention of our employees are focused on our LNG receiving terminal development business.

Competition and Markets

In the United States, due mainly to a historically abundant supply of natural gas, LNG has not been a major energy source. Furthermore, LNG may not become a competitive factor in the U.S. oil and gas industry. Although the LNG receiving business is in its developmental stages, companies in the U.S. are, nonetheless, exploring the possibility of engaging or developing an LNG business.

In the event that we complete LNG receiving facilities, the profitability of our operations and the price of our gas will be dependent on the availability of liquefied natural gas, the volume and price of domestic production of natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the political conditions in international oil-producing regions, taxation and the domestic demand for natural gas.

Government 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 permits and other authorizations before commencement of construction and operation of our LNG receiving terminals.

Failure to comply with such laws can result in substantial penalties. This regulatory burden increases the cost of constructing and operating the LNG receiving terminals, but we do not expect such regulatory compliance matters to have a material adverse effect on our financial position or results of operations.

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.” The FERC permitting process includes detailed engineering and design work, preparation of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings.

Department of Transportation/Coast Guard Regulations

Our LNG receiving terminals will also be subject to Department of Transportation and Coast Guard regulations relating to:

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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 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:

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 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 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.

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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.

Oil and Gas Exploration and Development

Although our current focus is primarily on the development of an LNG receiving terminal business, we continue to be involved in oil and gas exploration, development and exploitation, and in exploitation of our existing 3D seismic database through prospect generation. We have historically focused on evaluating and generating drilling prospects using a regional and integrated approach with a large seismic database as a platform. We expect that our oil and gas exploration activities will continue in the Gulf of Mexico, through active interpretation of our seismic data and generation of prospects, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne by industry partners. Our current oil and gas exploration and development activities are focused on two areas:

Our officers and technical staff have extensive experience both onshore and offshore in the Gulf Coast and believe that we are well-positioned to evaluate, explore and develop properties in these areas.

Cameron Project Seismic Exploration Program

We were formed in 1996 to fund the acquisition of a proprietary seismic database along the transition zone (the area approximately 3 to 5 miles on either side of the Gulf of Mexico shore line) in Cameron Parish, Louisiana. Under the terms of an exploration agreement with an industry partner, we paid for certain seismic costs in the amount of approximately $16,500,000 and acquired a 50% ownership interest in the seismic data covering the Cameron project, among other interests that have subsequently expired or terminated. After the termination of the exploration agreement, we purchased our partner’s 50% interest in the seismic data for $500,000 and sold all of the seismic data to a seismic marketing company for $3,325,000. We now retain a license to all of the seismic data for use in our exploration program. We are also entitled to receive at no additional cost any subsequent reprocessing of the data, which may be performed by the seismic marketing company.

In 1999, we licensed 8,800 square miles of seismic data from Fairfield Industries (the “Offshore Louisiana Area”) and made a commitment to fund the reprocessing of the entire 8,800-square-mile seismic database. In 2000, we entered into an agreement with Warburg, Pincus Equity Partners, L.P., a global private equity fund based in New York, to fund exploration and development in the Offshore Louisiana Area through a then newly formed private corporation, Gryphon Exploration Company (“Gryphon”). See “Investment in Gryphon Exploration Company.”

Seismic Exploration Program in Offshore Texas Project Area

In 2000, we acquired two licenses to an aggregate of approximately 1,900 square miles of seismic data from Seitel Data Ltd., a division of Seitel Inc. In October 2000, we exercised our option to expand the agreement with Seitel Data Ltd. to cover an additional 1,900 square miles of seismic data. Together, the licenses acquired from Seitel represent coverage of over 433 Outer Continental Shelf blocks in the shallow waters offshore Texas and Louisiana in the Gulf of Mexico. In 2001, we sold to Gryphon for $3,500,000 one of our two licenses to the Seitel 3D seismic data. We retain one license to the Seitel 3D seismic data.

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In 2000, we also negotiated a Master Data Users Agreement with the Houston-based firm, Jebco Seismic L.P., to acquire 3,000 square miles (333 blocks) of seismic data in both state and federal waters offshore Texas, bringing our total data set in the shallow waters offshore Texas and Louisiana to approximately 6,800 square miles of seismic coverage. As of December 31, 2003, we had received reprocessed data for the 3,000 square miles of seismic data in the Jebco data set and the 3,800 square miles of seismic data in the Seitel data set, representing all of the reprocessing to be done in the Offshore Texas Project Area.

In 2001, we sold to Gryphon for $3,500,000 one of our two licenses to the Jebco 3D seismic data covering an additional 3,000 square miles. We retain one license to the Jebco 3D seismic data.

Our exploration team generated and captured 21 prospects during 2001, 2002 and 2003 and sold interests in 19 of the prospects to industry partners, retaining various overriding royalty interests and working interests ranging from an overriding royalty interest (a share of the hydrocarbons produced from an oil and gas property, free of the expense of production) of less than 1% to a carried working interest (an agreement whereby we retain an interest in a well but bear none or only a portion of the cost of drilling the initial well) of approximately 24%. Fifteen of the prospects sold during 2001, 2002 and 2003 have been drilled by our industry partners, and we expect that the remaining prospects sold during those years will be drilled by our industry partners during 2004, but we do not serve as operator of the wells and do not control the timing of such drilling activities.

Drilling Activities

During 2001, 2002 and 2003, we did not participate in the drilling of any wells. Eight wells, however, were drilled during 2002 and nine wells were drilled in 2003 by our industry partners on prospects that we generated. During 2002, six of the eight wells were productive, and during 2003, seven of the nine wells were productive. We currently do not have a cost-bearing interest in the wells; we hold overriding royalty interests (ranging from 0.7% to 3.7%), some of which are convertible into working interests ranging from 12.5% to 20% at payout.

Investment in Gryphon Exploration Company

Cheniere owns 100% of the outstanding common stock of Gryphon. However, after giving effect to the potential conversion of all shares of Gryphon’s convertible preferred stock to shares of Gryphon common stock, we effectively had a 9.3% ownership interest in Gryphon as of December 31, 2003. Although historically we had the ability to exercise significant influence over Gryphon because of our participation on the Gryphon board of directors, we lost the ability to exercise such influence when our representation on Gryphon’s board was reduced to one director in December 2002. As a result, effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting (see Note 6 in the Notes to the Consolidated Financial Statements). Accordingly, no disclosures concerning Gryphon’s 2003 activity are included in this Form 10-K.

In 2000, we contributed to Gryphon the license to 8,800 square miles of seismic data that we had originally licensed from Fairfield Industries. The data covered more than 1,100 outer continental shelf blocks in the shallow waters of the Gulf of Mexico (the Offshore Louisiana Area). We also assigned our rights in our Joint Exploration Agreement with Samson, which ran from March 2000 through August 2001. For a description of licenses sold to Gryphon in 2001, see “Seismic Exploration Program in Offshore Texas Project Area.”

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Production and Sales

The following table presents certain information with respect to our oil and natural gas production, average sales prices received and average production costs during 2001, 2002 and 2003. In April 2002, we sold our interests in the Redfish and Stingray wells on West Cameron Block 49, representing all of our directly-owned producing properties at the time.

Acreage and Wells

The following table sets forth certain information with respect to our developed and undeveloped leased acreage as of December 31, 2003.

At December 31, 2003, we had no working interest in any producing wells; we had overriding royalty interests in eleven wells.

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Oil and Gas Reserves

All of the information herein regarding estimates of our proved reserves, related future net revenues and PV-10 as of December 31, 2003 is taken from reports generated by Sharp Petroleum Engineering, Inc., our independent petroleum engineers, in accordance with the rules and regulations of the SEC. The independent engineers’ estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data that we provided.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, our reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

In accordance with SEC guidelines, the estimates of future net revenues from our proved reserves and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. We may receive amounts different than the estimates for a number of reasons, including changes in prices. See Supplemental Information to Consolidated Financial Statements. Estimates of our proved oil and gas reserves were not filed with or included in reports to any other federal authority or agency other than the SEC during the fiscal year ended December 31, 2003.

Business Strategy

Our objective in the Exploration and Development business is to expand the net value of our assets by building an oil and gas reserve base in a cost-efficient manner, through exploitation of our seismic database to facilitate identifying drilling prospects.

Seismic Data

We have acquired the following two significant seismic database assets:

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The offshore Texas database has been available previously to the industry and was processed using a technique called dip move out (“DMO”). We acquired the DMO data and underwrote the reprocessing of the data utilizing another technology known as prestack time migration (“PSTM”). Both DMO and PSTM are processing techniques which improve seismic data quality to more accurately image subsurface features and delineate hydrocarbon accumulations. Of the two techniques, PSTM is more advanced and technically accurate. The regional PSTM data is the technology tool which management believes gives us a competitive advantage.

Analysis and Methodology

We have developed a prospect generation infrastructure capable of detailed analyses of large volumes of seismic, geological and engineering data. We employ a rigorous methodology which includes:

By conducting a thorough analysis of the data and strict adherence to the methodology, we believe that we can reduce the risk of dry holes and achieve significant growth, while maintaining a competitive cost of exploration and development.

Experience

We have built a technical and management team that is experienced in the Gulf of Mexico and in various technical specialties required for our exploration program. The technical staff averages over 30 years of experience exploring for oil and gas in the Gulf Coast. We believe that this experienced team allows us to be very productive in the generation and acquisition of prospects.

Competition and Markets

The availability of a ready market for and the price of any hydrocarbons that we produce will depend on many factors beyond our control, including the extent of domestic production and imports of foreign oil, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the political conditions in international oil-producing regions, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of natural gas. In the past, as a result of excess deliverability of natural gas, many pipeline companies curtailed the amount of natural gas taken from producing wells, shut in some producing wells, significantly reduced gas taken under existing contracts, refused to make payments under applicable take-or-pay provisions and have not contracted for gas available from some newly completed wells.

In addition, the restructuring of the natural gas pipeline industry has eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas, therefore, have been required to develop new markets among gas marketing companies, end-users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing area, generally may affect the supply and/or demand for oil and gas and thus the prices available for sales of oil and gas.

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Competition in the industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. We compete with the major oil companies and other independent producers of varying sizes, all of which are engaged in the exploration, development and acquisition of producing and non-producing properties.

Government Regulation

Our oil and gas exploration, development and related operations are subject to extensive federal, state and local statutes, rules, regulations, and other laws. Failure to comply with such laws can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability.

MMS Regulations

We conduct certain activities on federal oil and gas leases which the Minerals Management Service, or “MMS”, administers. The MMS grants leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to The Outer Continental Shelf Lands Act (“OCSLA”). For example, for offshore operations, we must comply with the following MMS requirements:

Bonding and Financial Responsibility Requirements

In connection with our ownership or operation of oil and gas leases, we are required by governmental agencies, including the MMS, to obtain bonding or otherwise demonstrate financial responsibility at varying levels. These bonds may cover such obligations as plugging and abandonment of wells, removal and closure of related exploration and production facilities, and pollution liabilities. The costs of such bonding and financial responsibility requirements can be substantial, and we may not be able to obtain such bonds and/or otherwise demonstrate financial responsibility in all cases.

Regulation of Production

Our oil and gas production operations are subject to state conservation laws and regulations, including:

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Such laws may restrict the rate at which the wells in which we have an interest may produce oil or gas, with the result that the amount or timing of our revenues could be adversely affected.

Natural Gas Marketing

FERC regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the NGA and the NGPA. Sales of our gas are currently not regulated and are made at market prices. However, in the past, the federal government has regulated the prices at which natural gas could be sold, and Congress could reenact price controls in the future.

Environmental Matters

Our oil and gas exploration, development and related operations are subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG operations. See “LNG Receiving Terminal Development—Government Regulation—Environmental Matters.” In addition, our oil and gas exploration, development and related operations are subject to the following:

NORM. The disposal of wastes containing Naturally Occurring Radioactive Material, which are commonly generated during oil and gas production, is regulated under state law. Typically, wastes containing naturally occurring radioactive material can be managed on site or disposed of at facilities licensed to receive such waste at costs that are not expected to be material.

Oil Pollution Act. The federal Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into waters of the United States (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any such oil spill. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay the costs of cleaning up an oil spill and to compensate any parties damaged by an oil spill. Such financial assurances may be increased to as much as $150 million if a formal assessment indicates such an increase is warranted.

Financial Information about Segments

During the last three fiscal years, all of our revenues have resulted from our oil and gas exploration and development activities. For information about our segments’ revenues, profits and losses and total assets, see Note 16 in Notes to Consolidated Financial Statements.

Subsidiaries

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.

Employees

We had 32 full-time employees as of February 27, 2004.

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RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. These important factors are not exclusive.

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.

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.

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 financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; marine congestion; 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.

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.

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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 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,

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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:

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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 included herein 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:

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:

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Do not interpret the PV-10 values included in this Form 10-K 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 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:

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.

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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 December 31, 2003. 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 December 31, 2003, we had $4,487,352 of current assets and working capital of $155,526. In January 2004, we received net proceeds of $13,884,750 from a private placement of 1,100,000 shares of our common stock, and we also received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to the sale of our 60% interest in the Freeport LNG project. In January and February 2004, we received net proceeds of $1,309,559 related to the issuance of 557,056 shares of common stock pursuant to exercises of warrants and stock options. We may need additional capital for a number of purposes. If we are unable to obtain additional financing, 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.

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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:

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 the LNG receiving terminal, the operations of such facility 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.

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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. While these regulations have existed for several years, they are undergoing extensive changes to fully implement the 2002 amendment to the Natural Gas Pipeline Safety Act. These new regulations are expected to be published in early 2004 and will focus primarily on ensuring the integrity of pipeline systems by requiring periodic inspection of pipeline facilities and repair of any defects discovered in the inspection process. We anticipate that the new rules will result in changes in the way we evaluate and document our pipeline integrity process. However, until the regulations are finalized, we will not know the exact nature of the new requirements nor can we estimate additional compliance costs, if any.

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.

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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 to 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.

Item 3. LEGAL PROCEEDINGS

We have been, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. Management regularly analyzes current information and as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of

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management and legal counsel, as of December 31, 2003, there were no threatened or pending legal matters that would have a material adverse impact on our consolidated results of operations, financial position or cash flows.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

Item 5. MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Stock has traded on the American Stock Exchange under the symbol LNG since March 24, 2003. Our common stock had previously traded on the American Stock Exchange under the symbol CXY from March 5, 2001 through March 23, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the American Stock Exchange, for each quarter during 2002 and 2003.

As of February 29, 2004, we had 18,659,994 shares of common stock outstanding held by approximately 4,200 beneficial owners.

We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects, and any restrictions under any credit agreements, as well as other factors the board of directors deems relevant.

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Item 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and Notes thereto included elsewhere in this report.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

We are 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. The LNG receiving terminal business consists of receiving deliveries of LNG from LNG ships, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers. We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

Results of Operations—Comparison of the Fiscal Years Ended December 31, 2003 and 2002

Overview—Our financial results for the year ended December 31, 2003 reflect a loss of $5,288,017, or $0.36 per share (basic and diluted), compared to a loss of $5,632,308 or $0.42 per share (basic and diluted) in 2002. The major factors contributing to our loss in 2003 were: LNG receiving terminal development expenses of $6,704,538 (which were offset by a $3,015,468 minority interest in the operations of our Corpus Christi LNG partnership), our equity share of the loss in the Freeport LNG limited partnership of $4,471,529 and other general and administrative expenses of $2,542,399. These factors are offset by a $4,760,000 gain on the sale of LNG assets and a $423,454 gain on the sale of a limited partnership interest in the Freeport LNG terminal.

LNG Terminal Development Activities—Our principal focus in both 2003 and 2002 was the development of LNG receiving terminals. As a result, terminal development expenses represented a major part of our operating costs and expenses for both years. In 2003, we phased out our direct involvement in developing the Freeport, Texas, site, but we accelerated the schedule of terminal development at two new sites located near Sabine Pass, Louisiana, and near Corpus Christi, Texas. Accordingly, gross terminal development expenses, before any cost recoveries, were 103% higher in 2003 ($6,704,538) than in 2002 ($3,297,208).

In 2003, we formed a limited partnership to develop the Corpus Christi LNG terminal. We are the general partner, and we own a 67% limited partner interest. We recorded $3,015,468 in terminal development expenses related to this site in 2003; however, this amount was completely offset by the minority interest of our 33% partner who provided funding for all development costs in 2003. The remainder of our 2003 terminal development expenses related to the Sabine Pass site, where we own 100% of the project.

In 2002, we incurred $3,297,208 in terminal development expenses for the Freeport LNG terminal. We entered into an agreement in August 2002 to sell a 60% interest in the terminal in exchange for payments to us totaling $5,000,000 over time and payments to others of up to $9,000,000 for expenses, which were already incurred or are to be incurred in connection with the development of the Freeport LNG terminal. During 2002, $1,740,426 in such development expenses were charged to the purchaser. This recovery reduced our terminal development expenses reported for 2002 to $1,556,782.

In February 2003, our Freeport LNG terminal project was acquired by Freeport LNG in which we received a 40% limited partnership interest in addition to the consideration described above. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4,760,000. Furthermore, we sold a 10% interest in Freeport LNG in March 2003 for $2,333,333, resulting in a gain of $423,454. Throughout 2003, we received payments totaling $2,500,000 from Freeport LNG, which amounts were recorded as a reduction to our investment in the partnership. In addition, our 30% limited partner interest in the operations of Freeport LNG resulted in our

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recording equity in the net loss of the partnership of $4,471,529 for 2003. This non-cash loss reduced our investment in Freeport LNG to zero.

Other General and Administrative Expenses—Other general and administrative (“G&A”) expenses relate to our general corporate and other activities. These expenses increased $623,819, or 33%, to $2,542,399 in 2003 compared to $1,918,580 in 2002. The principal components of G&A are employee compensation and contracted services, legal fees and travel. We expanded our staff from 13 to 17 throughout 2003 as we expanded our business. We incurred more legal expenses in connection with securities compliance filings and increased securities registration costs. We traveled more as we increased our profile among the investment community and as we developed an LNG trading venture based in Europe.

Oil and Gas Activities—Oil and gas revenues increased by $418,412, or 175%, to $657,467 in 2003 from $239,055 in 2002 as a result of increased production volumes (123,494 Mcfe in 2003 compared with 94,441 Mcfe in 2002) and increased average natural gas prices of $5.33 per Mcf in 2003 from $2.58 per Mcf in 2002. We had production from 11 wells in 2003 as compared with six wells in 2002. We incurred no production costs in 2003 because all of our revenues were generated from non-cost bearing overriding royalty interests. Production costs in 2002 totaled $90,038 and related to the early months of 2002 before we sold our cost-bearing working interests in oil and gas properties.

Equity in Net Loss of Unconsolidated Affiliate—On January 1, 2003, we began accounting for our interest in Gryphon on the cost method of accounting because we no longer had sufficient board representation to provide us with the opportunity to exert significant influence over the financial and operating policies of the company. In 2002, we accounted for our investment using the equity method of accounting, and our equity share of Gryphon’s losses was $2,184,847.

Results of Operations—Comparison of the Fiscal Years Ended December 31, 2002 and 2001

Overview—Our financial results for the year ended December 31, 2002 reflect a loss of $5,632,308, or $0.42 per share (basic and diluted), compared to a loss of $11,665,262 or $0.89 per share (basic and diluted) in 2001. The major factors contributing to our loss in 2002 were: LNG terminal development expenses of $3,297,208 (offset by cost recoveries of $1,740,426) for a net cost of $1,556,782, other general and administrative expenses of $1,918,580, and equity in loss of unconsolidated affiliate of $2,184,847.

LNG Terminal Development Activities—Throughout 2002 and 2001, our operations were primarily focused on the development of a potential LNG terminal site near Freeport, Texas. Gross terminal development expenses, before any cost recoveries, incurred in 2002 ($3,297,208) were 84% higher than in 2001 ($1,788,419). The increased level of expenditures relates principally to the advancing stages of the project and the acceleration of work leading to the filing of an application with FERC in March 2003.

In August 2002, we entered into an agreement to sell a 60% interest in the Freeport LNG terminal in exchange for payments to us totaling $5,000,000 and additional payments of up to $9,000,000 for expenses which were already incurred or to be incurred later in connection with the development of the Freeport LNG terminal. During 2002, $1,740,426 in such development expenses were charged to the purchaser. This recovery reduced our terminal development expenses reported for 2002 to $1,556,782.

Oil and Gas Activities—Oil and gas revenues decreased to $239,055 in 2002 from $2,372,632 in 2001 as a result of decreased production volumes (94,441 Mcfe in 2002 compared with 558,422 Mcfe in 2001). The decline in production volumes primarily results from the sale of our two producing wells at West Cameron Block 49 in April 2002. Adding to the effect of declining production was a decrease in average gas prices to $2.58 per Mcf in 2002 compared to $4.48 per Mcf in the prior year. Production costs decreased 79% to $90,038 in 2002 from $420,242 in 2001.

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Depreciation, depletion and amortization (“DD&A”) decreased to $368,562 in 2002 from $1,243,828 in 2001 as a result of both the decline in our production volumes, described above, and a lower DD&A rate per unit ($0.79 per Mcfe versus $1.84 per Mcfe). Our DD&A rate declined due to our change in emphasis toward selling prospects for front-end fees plus carried interests, as opposed to direct participation in drilling costs, and due to the effect of our $5,126,248 ceiling test write-downs recorded in 2001.

Other General and Administrative Expenses—G&A related to our general corporate and other activities, decreased $584,964, or 23%, to $1,918,580 in 2002 compared to $2,503,544 in 2001. The major components of the decrease were in legal fees, investor relations expenses and franchise taxes. Legal fees were lower in 2002 because in 2001 they included costs related to the buyout of our partner’s interest in the seismic data set of the Cameron Project and a higher level of securities compliance filings and securities registration costs than in 2002. Our investor relations efforts in 2002 were less extensive than in 2001 when we made a concerted effort to communicate with the investment community about our completed transaction with Warburg to form our affiliate, Gryphon, and our new listing on the American Stock Exchange. Franchise taxes were lower in 2002 because we had a reverse stock split, which reduced our authorized shares from 120,000,000 shares to 40,000,000 during 2000.

Equity in Loss of Unconsolidated Affiliate—Equity in net loss of unconsolidated affiliate includes our share of the net loss of Gryphon, but also Gryphon’s preferred dividends in arrears. The amount we recognized for 2002 decreased to $2,184,847 from $2,974,191 in 2001 because during 2002 our recognition of these non-cash charges reduced our investment basis to zero. We did not reduce our basis below zero because we did not guarantee any obligations of Gryphon and were not committed to provide additional financial support to Gryphon.

Liquidity and Capital Resources

Management expects that we will meet all of our liquidity requirements for the next twelve months through a combination of cash balances, collection of receivables, issuances of our debt or equity securities, issuances of common stock pursuant to exercises by the holders of existing warrants and options, sales of regas capacity in our planned LNG receiving terminals, sales of prospects generated by our exploration group, borrowings under our line of credit and cash flows from current operations. In the event that we are unable to obtain additional capital from one or more of these sources, our operations could be adversely affected.

At December 31, 2003, we had working capital of $155,526. In January 2004, we received net proceeds of $13,884,750 from a private placement of 1,100,000 shares of our common stock, and we also received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to the sale of our 60% interest in the Freeport LNG project. In January and February 2004, we received net proceeds of $1,309,559 related to the issuance of 557,056 shares of common stock pursuant to exercises of warrants and stock options. The pro forma effect of these transactions, had they been consummated as of December 31, 2003, would have been to increase our working capital to $17,849,835.

Cash Flow from Operating Activities

Net cash used in operations for the year ended December 31, 2003 totaled $7,558,864, compared to net cash used in operations of $2,764,325 in 2002. Because most of our resources were dedicated to the development of LNG receiving terminals in both 2002 and 2003, the main reason for the increase is that we were involved in the development of three LNG receiving terminals during 2003 as compared with only one terminal throughout most of 2002.

Issuances of Common Stock

Since our inception, the primary source of financing for our operating expenses, investments in our exploration program and investments in our development of LNG receiving terminals has been the sale of our

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equity securities. Through December 31, 2003, we have issued 16,488,187 shares of Cheniere common stock, generating net proceeds of $43,462,992. During 2003 and 2001, we raised $4,372,032 and $493,329, respectively, net of offering costs, from the exchange or exercise of warrants, the exercise of stock options and the sale of Cheniere units (common stock and warrants) to accredited investors pursuant to Regulation D. Proceeds of the offerings were used for the development of LNG receiving terminals and for general corporate purposes.

We issued a total of 3,190,794 shares of common stock in 2003. In April 2003, we issued 750,000 shares of common stock pursuant to a contingent contractual obligation related to Cheniere’s 2001 acquisition of an option to lease the Freeport LNG terminal site. In May 2003, we issued 792,892 shares of common stock to seventeen investors in a private placement made pursuant to Regulation D. The purchase price of the shares included cash of $1,189,338 and the surrender of existing warrants to purchase 792,892 shares of our common stock. Offering expenses relating to the private placement were $57,956. In August 2003, we issued 378,308 shares pursuant to a cashless exercise of warrants to purchase 700,000 shares. Throughout 2003, we issued a total of 1,082,094 shares pursuant to the exercise of warrants, resulting in net cash proceeds of $2,948,385. We also issued 187,500 shares pursuant to the exercise of stock options, resulting in proceeds of $292,265.

We did not sell any equity securities in 2002. In 2001, we issued a total of 750,000 shares of common stock. In February 2001, we issued to one stockholder 250,000 units at a cash purchase price of $2.00 per unit, each unit consisting of one share of Cheniere common stock, $.003 par value per share, and one warrant to purchase one-sixth of a share of Cheniere common stock. Proceeds of the offering, net of offering costs, were $493,329. In June 2001, we issued 500,000 shares of Cheniere common stock as partial consideration for a lease option on an LNG receiving terminal site near Freeport, Texas.

Bank Line of Credit

On July 25, 2003, we established a $5,000,000 line of credit with a commercial bank, with an initial borrowing base of $2,000,000. The facility is secured by our assets, and its term runs through December 31, 2004. Borrowings bear interest at the bank’s prime rate plus 2.5% per annum. In addition, a commitment fee of 0.5% per annum is assessed on the unused borrowing base capacity. A loan origination fee of 1% of the initial borrowing base was paid at closing. During 2003, we borrowed $1,000,000 under the facility to acquire oil and gas leases. The balance was repaid in January 2004. We also used the facility to establish a standby letter of credit in the amount of $865,142 in connection with our office lease.

Short-Term Promissory Notes

In February 2003, we executed a promissory note payable in the amount of $225,000. The proceeds of the note were used to pay certain costs related to our 3-D seismic database. In July 2003, we repaid the note payable.

In June 2002, we received a $750,000 payment for the sale of options to purchase an aggregate of up to a 20% interest in the Freeport LNG receiving terminal project. The payment was refundable, and repayment was secured by a note payable that we executed. In March 2003, an option was exercised and the note payable was canceled.

Sale of Interest in Freeport LNG Terminal

In August 2002, we entered into an agreement to sell a 60% interest in our planned LNG receiving facility near Freeport, Texas. In February 2003, our Freeport LNG project was acquired by Freeport LNG Development, L.P., in which we held a 40% interest. Effective March 1, 2003, we sold a 10% interest in Freeport LNG to an affiliate of Contango Oil & Gas Company for $2,333,333 payable over time. We now retain a 30% interest in Freeport LNG. Freeport LNG paid us cash and assumed liabilities related to the Freeport LNG project for costs, which represented an aggregate amount of $1,740,426, in addition to paying us a $1,000,000 initial installment at

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closing. We received additional payments of $1,500,000 in 2003 and $2,500,000 in January 2004 from Freeport LNG.

In June 2003, Dow signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal. Under the agreement, Dow will have regas rights to as much as 500 Mmcf/d beginning with commercial start-up of the facility in 2007. In February 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 regas capacity and an option by Dow until August 2004 to acquire an additional 250 Mmcf/d of regas capacity.

On December 21, 2003, ConocoPhillips and Freeport LNG signed an agreement under which ConocoPhillips will reserve one Bcf per day of regas capacity in the terminal at the Freeport facility. ConocoPhillips will also obtain a 50% interest in the general partner of Freeport LNG and provide a substantial majority of the financing to construct the facility, which is currently estimated to cost in excess of $500 million. The ConocoPhillips transaction is expected to close in the spring of 2004, subject to completion of remaining documentation and satisfaction of closing conditions.

Because the initial development expenses of the Freeport LNG project are to be funded by the 60% limited partner in Freeport LNG, we have not been required to contribute any cash to Freeport LNG for development activities, nor do we anticipate being required to make capital contributions to Freeport LNG in the future.

Corpus Christi LNG Terminal Funding Negotiations

Under the terms of the limited partnership agreement of Corpus LNG, which was formed for our Corpus Christi LNG receiving terminal project, 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 LNG. 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 $4,500,000 of Corpus LNG project expenses in exchange for a 33.3% limited partner interest. We will manage the project through the general partner interest held by our wholly-owned subsidiary.

Exploration Funding

On October 11, 2000, we completed a transaction with Warburg to fund our exploration program on approximately 8,800 square miles of seismic data in the Gulf of Mexico through a newly formed affiliated company, Gryphon. We contributed selected assets and liabilities in exchange for 100% of the common stock of Gryphon (36.8% effective interest after conversion of preferred stock) and $2,000,000 in cash. Warburg contributed $25,000,000 and received preferred stock, with an 8% cumulative dividend, convertible into 63.2% of Gryphon’s common stock.

Cheniere and Warburg also have the option, in connection with subsequent capital calls made by Gryphon, to contribute up to an additional $75,000,000 to Gryphon, proportionate to their respective ownership interests. Under the terms of the agreement governing these additional contributions, in the event that either we or Warburg elects not to participate in any additional contribution, the other investor has the option to purchase the non-participating investor’s proportionate share. During 2001 and 2002, Gryphon made cash calls totaling $60,000,000 against its capital commitment of $75,000,000. Gryphon made no additional cash calls during 2003. We declined to participate in such cash calls, and Warburg elected to purchase our proportionate share of such cash calls. As a result, our ownership interest in Gryphon, after the potential effect of converting preferred stock into common stock, was reduced from 36.8% at December 31, 2000 to 9.3% as of December 31, 2003.

Prior to 2003, we accounted for our investment in Gryphon using the equity method of accounting. Effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting because we lost the ability to exercise significant influence over Gryphon’s operating and financial policies, as our representation on Gryphon’s board of directors was reduced to one director.

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Seismic Reprocessing

Between June 2000 and October 2000, we acquired licenses to approximately 6,800 miles of seismic data primarily in the shallow waters offshore Texas and also in the West Cameron area in the Gulf of Mexico (the “Offshore Texas Project Area”) in separate transactions with Seitel Data Ltd., a division of Seitel Inc., and Jebco Seismic, L.P. We committed to reprocess all of the data from the Offshore Texas Project Area at a cost of approximately $8,500,000, payable in installments beginning in October 2000 and continuing through the final delivery of reprocessed data, which was received in 2003. We have no existing or contingent liability related to seismic reprocessing as of December 31, 2003.

Sale of Licenses to Seismic Data

In June and July 2001, we sold licenses to 6,800 square miles of seismic data to Gryphon for $7,000,000. We received cash proceeds of $853,197. Gryphon also assumed $6,820,824 of our obligation to fund the reprocessing of the seismic data. In connection with the transactions, we also transferred 6,740 shares of Gryphon common stock to Gryphon. We retain one license to all of the data in the Offshore Texas Project Area.

Sale of Proprietary Seismic Data

In September 2001, we acquired for $500,000 all rights to our 228-square-mile proprietary seismic database from the industry partner with whom we had jointly acquired the data in 1996 and 1997. We subsequently sold the seismic data to a seismic marketing company for $2,500,000 and a 50% share in licensing proceeds generated by the marketing company. In September 2002, we sold our remaining interest in future licensing proceeds to the marketing company for $825,000. Proceeds from the September 2001 and 2002 sales of 3D seismic data were recorded as a reduction to our unproved oil and gas property costs. We retain a license to all of the seismic data for use in our exploration program.

Contractual Obligations

We are committed to making cash payments in the future on certain of our contracts. We have no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2003.

Our obligations under LNG site options are renewable on an annual or semiannual basis. We may terminate our obligation at any time by electing not to renew or by exercising the option.

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Other Matters

Critical Accounting Estimates and Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and believe the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them, and often consult with our independent accountants about the appropriate interpretation and application of these policies. Our most critical accounting policy is our accounting under the full cost method of accounting. This area involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements.

Accounting for LNG Activities

We have been in the preliminary stage of developing LNG receiving terminals. Substantially all costs related thereto have been expensed when incurred. Land costs associated with LNG terminal sites are capitalized. Costs of certain permits are capitalized as intangible LNG assets. We have also incurred costs related to options to purchase or lease land that may be used for potential LNG terminal sites.

Full Cost Method of Accounting

We follow the full cost method of accounting for our oil and gas properties. Under this method, all productive and non-productive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. Interest is capitalized on oil and gas properties not subject to amortization and in the process of development.

The costs of our oil and gas properties, including the estimated future costs to develop proved reserves, are depreciated using a composite units-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs to be amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties, less related income tax effects. At June 30, 2001 and September 30, 2001, our capitalized costs exceeded our capitalization ceiling, resulting in ceiling test write-downs totaling $5,126,248 for the year.

Our allocation of seismic exploration costs to proved properties involves an estimate of the total reserves to be discovered in the project. This estimate includes a number of assumptions that we have factored into a four-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. We transfer unproved properties to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in our exploration program. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate could affect our capitalization ceiling.

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Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.

Our proved reserve information included in this document for 2003 is based on estimates prepared by Sharp Petroleum Engineering, Inc. Estimates prepared by others may be higher or lower than our estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of natural gas and crude oil that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

The present value of future net cash flows does not necessarily represent the current market value of our estimated proved natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimate of proved reserves declines, the rate at which we record DD&A expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields.

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 have not identified any variable interest entities. In the event a variable interest entity is identified, we do not expect the requirements of FIN 46R to have a material impact on our consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. An issuer is required to classify a financial instrument that is within the scope of this statement as a liability (or an asset in some circumstances). SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We adopted the standard on July 1, 2003, and the adoption did not have a material impact on our consolidated financial statements.

Other Recent Developments

In July 2003, an issue was brought before the Financial Accounting Standards Board (FASB) regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets

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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. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how we classify these assets.

Should such a change be required, the amounts related to business combinations and major asset purchases that would be classified as “intangible undeveloped mineral interest” are immaterial as of December 31, 2003 and December 31, 2002. The amounts related to business combinations and major asset purchases that would be classified as “intangible developed mineral interest” are also immaterial as of December 31, 2003 and December 31, 2002.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The development of our LNG receiving terminal business is based upon the foundational premise that prices of natural gas in the U.S. will be sustained at levels of $3.00 per Mcf or more. Should the price of natural gas in the U.S. decline to sustained levels below $3.00 per Mcf, our ability to develop and operate LNG receiving terminals could be significantly negatively affected.

We produce and sell natural gas, crude oil and condensate. As a result, our financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. We have not entered into any derivative transactions.

In the normal course of business, our financial condition is exposed to minimal market risk associated with interest rate movements on our borrowings. A one percent increase or decrease in the levels of interest rates on variable rate debt would not result in a material change to our results of operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

All schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and

Stockholders of Cheniere Energy, Inc:

We have audited the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Freeport LNG Development, L.P. (“Freeport LNG”), an investment which, as discussed in note 7 to the consolidated financial statements, is accounted for by the equity method of accounting. The investment in Freeport LNG was zero as of December 31, 2003 and 2002, and the equity in its net loss was $4,471,529 and zero, respectively, for the years then ended. We also did not audit the financial statements of Gryphon Exploration Company (“Gryphon”), an investment which, as discussed in Note 6 to the consolidated financial statements, has been, until January 1, 2003, accounted for by the equity method of accounting. The investment in Gryphon was zero as of December 31, 2003 and 2002, and the equity in its net loss was $2,184,847 for the year ended December 31, 2002. The financial statements of Freeport LNG and Gryphon were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Freeport LNG and Gryphon, are based solely on the reports of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.

MANN FRANKFORT STEIN & LIPP CPAs, L.L.P.

Houston, Texas

February 29, 2004

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and

Stockholders of Cheniere Energy, Inc:

In our opinion, the consolidated statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2001 present fairly, in all material respects, the results of operations and cash flows of Cheniere Energy, Inc. and its subsidiaries for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 18 to the consolidated financial statements, the Company has experienced recurring losses from operations and has a negative working capital balance at December 31, 2001 that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 18. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas

March 29, 2002, except for Note 16 as to

which the date is March 25, 2004

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

The accompanying notes are an integral part of these financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

The accompanying notes are an integral part of these financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY