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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: