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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

OR

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) 375-5000

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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  x  No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes  ¨  No  x

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.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller company filer. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨  No  x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1,735,000,000 as of June 29, 2007.

48,605,369 shares of the registrant’s Common Stock were outstanding as of February 15, 2008.

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 are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “potential,” “forecast,” “plan,” “project,” “propose,” “strategy” 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.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements are made as of the date of this annual report.

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DEFINITIONS

In this annual report, unless the context otherwise requires:

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

Cheniere Energy, Inc., a Delaware corporation, is a Houston-based company engaged, through its subsidiaries, in the energy business generally. As used in this annual report, the terms “Cheniere”, “we”, “us” and “our” refer to Cheniere Energy, Inc. and its subsidiaries, including our publicly traded subsidiary partnership, Cheniere Energy Partners, L.P. (“Cheniere Partners”). We are currently engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore LNG receiving terminals and natural gas pipelines, and we are also developing a business to market LNG and natural gas, primarily through our wholly-owned subsidiary, Cheniere Marketing, Inc. (“Cheniere Marketing”). To a limited extent, we continue to be engaged in oil and natural gas exploration and development activities in the Gulf of Mexico.

Our common stock has been publicly traded since July 3, 1996 and is currently traded on the American Stock Exchange under the symbol “LNG”. Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is http://www.cheniere.com. 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 (“SEC”) under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes, nor is it incorporated by reference into this Form 10-K.

Cheniere Energy Partners

In March and April 2007, we and Cheniere Partners completed a public offering of 15,525,000 Cheniere Partners common units. Cheniere Partners received $98.4 million of net proceeds, after deducting the underwriting discount and structuring fees, upon issuance of 5,054,164 common units to the public in the

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offering. Cheniere Partners invested the $98.4 million of net proceeds that it received from the offering in U.S. treasury securities to fund a distribution reserve. As part of the offering, we, as a selling unitholder, received $203.9 million of net proceeds in connection with the sale of 10,470,836 of our Cheniere Partners common units to the public. In connection with the offering and in exchange for Cheniere Partners common and subordinated units, we contributed the equity interests in the entity owning the Sabine Pass LNG receiving terminal to Cheniere Partners. As a result of the offering, our ownership interest in Cheniere Partners is approximately 90.6%.

Business Segments

Our business activities are conducted by four reporting segments for which we provide information in our financial statements for the years ended December 31, 2007, 2006 and 2005 as required under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.” These four segments are our:

Overview of the LNG Industry

LNG is natural gas that, through a refrigeration process, has been reduced to a liquid state, which represents approximately 1/600th of its gaseous volume. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to justify economically the use of LNG. LNG is transported using large oceangoing LNG tankers specifically constructed for this purpose. LNG receiving terminals offload LNG from LNG tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market.

Our Business Strategy

We are pursuing a business strategy with the following primary components:

On February 25, 2008, we announced that we are evaluating strategic options to enhance shareholder value, including options to optimize the value of the Sabine Pass LNG receiving terminal and the regasification capacity at the facility held under a long-term TUA by Cheniere Marketing.

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LNG Receiving Terminal Business

We began developing our LNG receiving terminal business in 1999 and, since then, have been among the first companies to secure sites and commence development of new LNG receiving terminals in North America. We have focused our development efforts on the following three LNG receiving terminal projects: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Partners, in which we hold an approximate 90.6% interest. In turn, Cheniere Partners owns a 100% interest in Sabine Pass LNG, L.P. (“Sabine Pass LNG”), which is currently constructing the Sabine Pass LNG receiving terminal. We currently own 100% interests in the both the Corpus Christi and Creole Trail LNG receiving terminal projects. In addition, we own a 30% interest in a fourth LNG receiving terminal project, Freeport LNG, located on Quintana Island near Freeport, Texas.

Sabine Pass LNG Receiving Terminal

Development

We are constructing the Sabine Pass LNG receiving terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. In 2003, we formed Sabine Pass LNG to own, develop and operate the Sabine Pass LNG receiving terminal. We have entered into leases for three tracts of land consisting of 853 acres in Cameron Parish, Louisiana for the project site. The Sabine Pass LNG receiving terminal was designed, and permitted by the FERC, with an initial regasification capacity of approximately 2.6 Bcf/d and three LNG storage tanks with an aggregate LNG storage capacity of approximately 10.1 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In June 2006, Sabine Pass LNG received approval from the FERC to increase the regasification capacity of the Sabine Pass LNG receiving terminal from approximately 2.6 Bcf/d to 4.0 Bcf/d (with peak capacity of 4.3 Bcf/d) and increase the aggregate LNG storage capacity from approximately 10.1 Bcf to 16.8 Bcf by adding up to three additional LNG storage tanks, additional vaporizers and related facilities.

Construction

In March 2005, the FERC issued an order authorizing Sabine Pass LNG to commence construction of the Sabine Pass LNG receiving terminal, subject to certain ongoing conditions. Sabine Pass LNG expects its EPC contractor, Bechtel Corporation, to complete construction and commissioning of the first three tanks, approximately 2.6 Bcf/d of regasification capacity, and associated facilities necessary to achieve initial commercial operations during the second quarter of 2008.

In June 2006, Sabine Pass LNG received authorization from the FERC to commence construction activities for the expansion of the Sabine Pass LNG receiving terminal, subject to certain ongoing conditions. The first stage of the expansion includes the addition of the fourth and fifth LNG storage tanks, and additional regasification capacity of approximately 1.4 Bcf/d. Sabine Pass LNG expects to complete the construction and commissioning of this stage of its expansion during the third quarter of 2009.

We estimate that the aggregate cost to complete construction of the Sabine Pass LNG receiving terminal will be approximately $1.4 billion, before financing costs. Our cost estimates are subject to change due to such items as cost overruns, change orders, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

Customers

The entire capacity of approximately 4.0 Bcf/d at the Sabine Pass LNG receiving terminal has been contracted under two 20-year, firm commitment TUAs with third parties, and one with our wholly-owned subsidiary Cheniere Marketing. Each of the customers at the Sabine Pass LNG receiving terminal must make the

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full contracted amount of capacity reservation fee payments under its TUA whether or not it uses any of its reserved capacity. Provided the Sabine Pass LNG receiving terminal has achieved commercial operation, which we expect will occur during the second quarter of 2008, capacity reservation fee TUA payments will be made by the Sabine Pass LNG customers as follows:

Under each of these TUAs, Sabine Pass LNG is also entitled to retain 2% of the LNG delivered for the customer’s account, which Sabine Pass LNG will use primarily as fuel for revaporation and self-generated power at the Sabine Pass LNG receiving terminal.

Each of Total and Chevron has paid us $20 million in nonrefundable advance capacity reservation fees, which will be amortized over a 10-year period as a reduction of each customer’s regasification capacity fees payable under its TUA.

Corpus Christi LNG Receiving Terminal

We are also developing the Corpus Christi LNG receiving terminal near Corpus Christi, Texas. We formed Corpus Christi LNG, L.P. (“Corpus Christi LNG”) in May 2003 to develop the terminal. The Corpus Christi LNG receiving terminal is located on 612 leased acres and was designed, and permitted by the FERC, with a regasification capacity of approximately 2.6 Bcf/d, three LNG storage tanks with an aggregate LNG storage capacity of approximately 10.1 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In December 2005, the FERC issued an order authorizing Corpus Christi LNG to commence initial construction of the Corpus Christi LNG receiving terminal, subject to satisfaction of certain conditions specified by the FERC. In order to accelerate the timing of its development of the Corpus Christi LNG receiving terminal, Corpus Christi LNG commenced in April 2006 preliminary site work, which has since been completed. Engineering and design work on the LNG receiving terminal is ongoing. We will contemplate making a final investment decision to complete construction of the Corpus Christi LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

Creole Trail LNG Receiving Terminal

We are also developing an LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We formed Creole Trail LNG, L.P. (“Creole Trail LNG”) in December 2004 to develop the terminal. We have options to lease tracts of land comprising 1,750 acres in Cameron Parish, Louisiana for the project site. The Creole Trail LNG receiving terminal was designed, and permitted by the FERC, with a regasification capacity of 3.3 Bcf/d, four LNG storage tanks with an aggregate LNG storage capacity of 13.5 Bcf and two unloading docks capable of handling the largest LNG carriers currently being

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operated or built. In June 2006, the FERC authorized Creole Trail LNG to site, construct and operate the Creole Trail LNG receiving terminal. We will contemplate making a final investment decision to commence construction of the Creole Trail LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

Other LNG Receiving Terminal Sites

We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG receiving terminals.

Other LNG Receiving Terminal Interests—Freeport LNG

We own a 30% limited partner interest in Freeport LNG Development, L.P. (“Freeport LNG”), which is constructing an LNG receiving facility on Quintana Island near Freeport, Texas. The first phase of the project includes regasification capacity of 1.75 Bcf/d, one dock, two LNG storage tanks with an aggregate LNG storage capacity of 6.7 Bcf, and a 9.4-mile, 42-inch diameter pipeline through which natural gas will be transported to customer redelivery points at Stratton Ridge, Texas. We currently expect that the first phase of the Freeport LNG receiving terminal project will commence operations in the second quarter of 2008. The proposed second phase, which has received FERC approval, includes additional regasification capacity of up to 2.25 Bcf/d, a second dock, and a third LNG storage tank. Freeport LNG is also currently constructing 7.5 Bcf of underground salt cavern storage at Stratton Ridge which is expected to be completed and integrated with the LNG receiving terminal operations in the first quarter of 2011.

Freeport LNG has entered into TUAs with three customers: The Dow Chemical Company for approximately 500 MMcf/d of regasification capacity; ConocoPhillips Company for approximately 900 MMcf/d of regasification capacity; and MC Global Gas Corporation, a wholly owned subsidiary of Mitsubishi Corporation, for approximately 150 MMcf/d of regasification capacity. We believe that Freeport LNG has obtained sufficient financing to fund the first phase of the project and a portion of the proposed second phase; as a result, we do not anticipate that any capital calls will be made upon us as a limited partner in Freeport LNG in the foreseeable future.

LNG Receiving Terminal Competition

New supplies to meet North America’s natural gas demand could be developed from a combination of the following sources:

In addition, demand for energy currently met by natural gas could alternatively be met by other energy forms such as coal, hydroelectric, oil, wind, solar and nuclear energy. LNG will face competition from each of these energy sources.

We compete with other companies to construct LNG receiving terminals in economically desirable locations. According to the FERC, as of January 14, 2008, there were six existing LNG receiving terminals in North America, including one offshore facility for receiving natural gas regasified from LNG onboard

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specialized LNG vessels, and other new LNG receiving terminals or expansions approved or proposed to be constructed. To the extent that we may desire to sell regasification capacity in our proposed LNG receiving terminals or resell some of our contracted regasification capacity, we will compete with other proposed third-party LNG receiving terminals or existing terminals having uncommitted capacity.

In addition, in connection with obtaining LNG for commissioning of the Sabine Pass LNG receiving terminal, Sabine Pass LNG must compete in the world LNG market to purchase and transport cargoes of LNG. Sabine Pass LNG may purchase and transport such cargoes at costs that may result in losses upon resale of the regasified LNG.

LNG Receiving Terminal Governmental Regulation

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

FERC

In order to site and construct our proposed LNG receiving terminals, we must receive and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (“NGA”). The FERC permitting process includes:

In addition, orders from the FERC authorizing construction of an LNG receiving terminal are typically subject to specified conditions that must be satisfied throughout the construction, commissioning and operation of terminals. Those conditions require us to:

In addition, throughout the life of our LNG receiving terminals, they will be subject to regular reporting requirements to the FERC and the Department of Transportation regarding the operation and maintenance of the facilities.

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Other Federal Governmental Permits, Approvals and Consultations

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

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

Energy Policy Act of 2005

In 2005, the Energy Policy Act of 2005 (“EPAct”) was signed into law. The EPAct gave the FERC exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG receiving terminal. The EPAct also amended the NGA to prohibit market manipulation and the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of the FERC up to $1 million per day per violation. The FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.

LNG Receiving Terminal Environmental Regulation

Our LNG receiving terminal 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 permits and authorizations before we may conduct certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or for pollution or releases of hazardous substances, materials or compounds or otherwise require additional costs or changes in operations that could have a material adverse effect on our business, results of operations, financial condition and prospects. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties. As with the industry generally, our operations will entail risks in these areas, and compliance with these laws and regulations increases our overall cost of business. While these laws and regulations affect our capital expenditures and earnings, we believe that these laws and regulations do not affect our competitive position in the industry because our competitors are similarly affected. Environmental laws and regulations have historically been subject to frequent revision and reinterpretation. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

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:

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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 LNG from its definition of “hazardous substances,” this exemption may be limited or modified by the U.S. Congress in the future.

Clean Air Act (CAA)

Our LNG receiving terminal operations are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over 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.

The U.S. Supreme Court has ruled that the Environmental Protection Agency (“EPA”) has authority under existing legislation to regulate carbon dioxide and other heat-trapping gases in mobile source emissions. In addition, Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” It is not possible at this time to predict how future regulations or legislation may address greenhouse gas emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Clean Water Act (CWA)

Our LNG receiving terminal operations are also subject to the federal CWA and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of wastewater and 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.

Resource Conservation and Recovery Act (RCRA)

The federal RCRA and comparable state statutes govern the disposal of “hazardous wastes.” In the event any hazardous wastes are generated in connection with our LNG receiving terminal operations, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Endangered Species Act

Our LNG receiving terminal operations and planned construction activities may also be restricted by requirements under the Endangered Species Act, 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.

Natural Gas Pipeline Business

We formed Cheniere Pipeline Company, a wholly-owned subsidiary, to develop natural gas pipelines that will provide access to North American natural gas markets for customers of our Sabine Pass and proposed Corpus Christi and Creole Trail LNG receiving terminals. We are also developing other pipeline projects not primarily related to our LNG receiving terminals. Our pipeline systems that are being developed in conjunction with our LNG receiving terminals will interconnect with multiple interstate pipelines, providing a means of delivering revaporized natural gas from our LNG receiving terminals to various North American natural gas markets. Our other projects are market focused, seeking to connect natural gas supplies to growing markets. Our ultimate decisions regarding pipeline connections to our facilities will depend upon future events, including, in particular, customer preferences and general market demand for natural gas from a particular LNG receiving terminal.

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Creole Trail Pipeline

Development

In October 2007, the FERC approved an application to merge our Sabine Pass Pipeline into our Creole Trail Pipeline, thereby creating an integrated pipeline system of approximately 150 miles in length. The Creole Trail Pipeline is being constructed in two phases. Phase 1, which is currently nearing completion of construction, consists of 94 miles of natural gas pipeline connecting with the Sabine Pass LNG receiving terminal and running easterly along a corridor that will allow for interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana. Phase 2, once constructed, will consist of approximately 59 miles of natural gas pipeline running from the terminus of Phase 1 east to a terminus near Rayne, Louisiana.

Construction

Construction of Phase 1 of the Creole Trail Pipeline commenced in the second quarter of 2007, and we anticipate that a portion of Phase 1 will be available for operations in the first quarter of 2008, with the remaining portion anticipated to be available for operations in the second quarter of 2008. We will contemplate making a final investment decision to construct Phase 2 of the Creole Trail Pipeline upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements. The total anticipated cost to construct Phase 1 of the Creole Trail Pipeline is approximately $550 million, before financing costs. Our cost estimates are subject to change due to such items as cost overruns, change orders, delays in construction, increased component and material costs and escalation of labor costs.

Customers

We offered our Creole Trail Pipeline capacity to potential customers through a formal open season process, and awarded Cheniere Marketing all of the capacity in the Creole Trail Pipeline. Cheniere Marketing has entered into a firm transportation agreement for transportation at a negotiated rate for the transport and sale of revaporized natural gas that it derives from its own imported LNG or LNG that it purchases from other importers for sale into North American markets. See “—LNG and Natural Gas Marketing Business” below. Cheniere Marketing’s capacity rights and obligations under the transportation precedent agreements may be assigned to unaffiliated customers with whom we enter into TUAs for our LNG receiving terminals capacity and who may also desire to enter into agreements for the transportation of revaporized gas on the Creole Trail Pipeline. Furthermore, we expect that other unaffiliated third-party shippers of domestic natural gas may desire transportation services in the Creole Trail Pipeline on at least an interruptible basis.

Corpus Christi Pipeline

We formed Cheniere Corpus Christi Pipeline, L.P., a wholly-owned subsidiary of Cheniere, to develop a 24-mile, 48-inch interstate natural gas pipeline that is designed to transport 2.6 Bcf/d of regasified LNG, from the Corpus Christi LNG receiving terminal northwesterly along a corridor that will allow for interconnection points with various interstate and intrastate natural gas transmission pipelines. The FERC issued an order in April 2005 authorizing us to construct, own and operate the Corpus Christi Pipeline, subject to specified conditions that must be satisfied. We will contemplate making an investment decision to commence construction of the Corpus Christi Pipeline upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements to build the Corpus Christi LNG receiving terminal.

Other Pipelines

We continue to evaluate, and may develop, additional pipelines that we believe may be commercially desirable based on customer preferences and general market demand for natural gas. Currently, we are evaluating the following pipeline projects.

Cheniere Southern Trail Pipeline

Cheniere Partners conducted a non-binding open season to gauge interest from prospective shippers in the proposed Cheniere Southern Trail Pipeline. Negotiations with open season respondents are ongoing. As currently

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contemplated, the Cheniere Southern Trail Pipeline would involve the construction of approximately 350 miles of up to 42-inch diameter pipeline that is currently estimated to cost approximately $1.5 billion, before financing costs. We will contemplate making a final investment decision to commence construction of the Cheniere Southern Trail Pipeline upon, among other things, entering into acceptable commercial arrangements, receiving FERC authorization to construct and operate the pipeline and obtaining adequate financing to construct the Cheniere Southern Trail Pipeline.

Frontera Pipeline

In September 2007, we entered into an equity purchase agreement with Tidelands Oil & Gas Corporation and acquired an 80% interest in Frontera Pipeline, LLC, an entity which owns 100% of Sonora Pipeline and Terranova Energia, and which together are developing the Burgos Hub Project. The Burgos Hub Project is a proposed integrated pipeline project traversing the United States and Mexico border and the potential construction of a related underground natural gas storage facility in Mexico. The aggregate cost to construct the project is currently estimated to be approximately $700 million to $800 million, before financing costs. Our cost estimate is subject to change due to such items as cost overruns, change orders, delays in construction, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule. We will contemplate making a final investment decision in the Burgos Hub Project upon, among other things, receiving all required authorizations to construct and operate the pipeline and storage facility, arranging appropriate financing and entering into acceptable commercial arrangements for the pipeline and storage facility.

Natural Gas Pipeline Competition

Our proposed pipelines will compete with intrastate and other interstate pipelines throughout our service territory. The principal elements of competition among pipelines are rates, terms of service, access to supply and flexibility and reliability of service. In addition, the FERC’s continuing efforts to increase competition in the natural gas industry are increasing the natural gas transportation options of a pipeline’s traditional customers.

Our pipelines will face competition from other intrastate and/or interstate pipelines that connect with our LNG receiving terminals. In particular, our Creole Trail Pipeline will compete with the proposed Kinder Morgan Louisiana Pipeline owned by Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). Kinder Morgan has announced that it is building a 3.2 Bcf/d take-away pipeline system from the Sabine Pass LNG receiving terminal. Total and Chevron have both announced agreements with Kinder Morgan securing 100% of the initial capacity on the Kinder Morgan Louisiana Pipeline for 20 years.

Natural Gas Pipeline Governmental Regulation

Interstate Natural Gas Pipelines

Under the NGA, the FERC is granted authority to set “just and reasonable rates” for the transmission or sale of natural gas in interstate commerce. It also gives FERC the authority to grant certificates allowing construction and operation of facilities used in interstate gas transmission and authorizing the provision of services. Under the FERC’s regulations, their jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use, and to natural-gas companies engaged in such transportation or sale. However, FERC’s jurisdiction does not extend to the production, gathering, or local distribution of natural gas.

In general, the FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:

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Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies, including civil and criminal penalties which were recently increased under the EPAct.

The natural gas industry historically has been regulated since 1938. Among other things, the FERC regulates the transportation rates and terms and conditions of service of interstate natural gas pipelines. See “—Rates” below. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines; however, the FERC may or may not continue this approach in the future.

We have received authorization from the FERC to provide firm and interruptible transportation services, as well as parking and lending services, for our pipelines based on cost of service rates. Beginning in the mid-1980s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

In November 2003, the FERC issued a series of orders adopting revised Standards of Conduct (Order No. 2004) that apply uniformly to interstate natural gas pipelines. These Standards of Conduct were designed to govern relationships between the pipeline and any energy affiliate, rather than governing conduct between the pipeline and its marketing affiliate. However, in 2006, Order No. 2004, as applied to natural gas pipelines, was vacated by a federal court, and the FERC issued an interim rule which expressly states that the Standards of Conduct do not govern the relationship between natural gas pipelines and our marketing employees. We have established the required policies and procedures to comply with the Standards of Conduct, and are subject to audit by the FERC to review compliance, policies and our training programs.

Our pipelines that interconnect with our LNG receiving terminals will be interstate natural gas pipelines requiring us to obtain authorization from the FERC pursuant to Section 7 of the NGA to construct and operate these pipeline facilities. The rates that we charge will be subject to the FERC’s regulation under Section 4 of the NGA. Our interstate pipelines will also be subject to the FERC’s open access requirements and the FERC’s Standards of Conduct as discussed above. The FERC’s exercise of jurisdiction over interstate natural gas pipelines is substantially broader than its exercise of jurisdiction over LNG receiving terminals.

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Natural Gas Pipeline Safety

Louisiana and Texas administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.

The Pipeline Safety Improvement Act of 2002 (“PSIA”), which is administered by the U.S. Department of Transportation Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transmission pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. In December 2003, the Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for gas transportation pipelines. The final rule requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions. This rule incorporates the requirements of the PSIA.

Energy Policy Act of 2005

The EPAct contains numerous provisions relevant to the natural gas industry and to interstate pipelines. See “—LNG Receiving Terminal Business Governmental Regulation—Energy Policy Act of 2005.”

Rates

Under the NGA, rates charged for the interstate transportation of natural gas must be just and reasonable and not unduly discriminatory or preferential. Amounts collected by the pipeline that the FERC finds unlawful are subject to refund with interest.

Natural Gas Pipeline Environmental Regulation

Our natural gas pipeline business is subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG receiving terminals. See “—LNG Receiving Terminal Business—LNG Receiving Terminal Environmental Regulation” above.

LNG and Natural Gas Marketing Business

Our wholly-owned subsidiary, Cheniere Marketing, is developing a natural gas and LNG marketing and trading business. Its principal asset is a TUA at the Sabine Pass LNG receiving terminal. We intend to build a portfolio of long-term and short-term and spot LNG purchase agreements from foreign suppliers, pursuant to which LNG will be delivered to either our LNG receiving terminals or other terminals with whom we will trade on the supplier’s vessels, or on vessels that we contract for our own use. In order to facilitate the importation of LNG into the U.S., we are also developing a portfolio of downstream natural gas sales agreements with major local distribution companies, power generators, industrial users and other gas marketing firms. We will also purchase domestic natural gas to satisfy our sales commitments during times that we elect to divert contracted supplies away from the U.S., or during times that we are not able to obtain LNG supplies.

In the course of engaging in the foregoing commercial activities, Cheniere Marketing has entered into, and will in the future enter into, various commercial transactions. These transactions include natural gas purchases

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and sales and options on natural gas purchases and sales, generally using master contracts promulgated by the North American Energy Standards Board (“NAESB contracts”) or the International Swap Dealers Association (“ISDA contracts”); short- and long-term natural gas transportation contracts with various domestic transporters, including firm, interruptible, capacity release and “parking and loan” agreements; short- and long-term natural gas storage agreements; natural gas processing agreements; financial derivatives agreements, generally using ISDA contracts; and futures and options on futures cleared on the NYMEX exchange through our brokerage agreements. Our marketing activities may also include the use of derivative transactions in order to take market positions or manage and hedge exposure to price, volume, timing, location, quality and credit risk associated with the marketing of LNG and natural gas. We have developed risk management policies, procedures and systems, which are reviewed regularly, to assist us in controlling and managing our marketing activities.

As a result of our acquisition of the remaining equity interest in J & S Cheniere S.A. (“J & S Cheniere”), we have acquired a 100% interest in time charter agreements for two LNG vessels. We plan to utilize these LNG tankers to transport LNG from foreign suppliers or merchants to LNG receiving terminals in the U.S. or to international markets if more favorable economic conditions exist in those markets.

LNG and Natural Gas Marketing Competition

Our LNG purchase efforts compete for supplies of LNG with:

Additionally, we compete for supplies against purchasers located in other countries, in which prevailing market prices can be substantially different, and frequently higher, than those in the U.S.

Our natural gas marketing efforts compete for sales of natural gas with a variety of competitors including:

LNG and Natural Gas Marketing Governmental Regulation

In 1992 and 1993, the FERC concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. The FERC established light-handed regulation over sales for resale of natural gas and adopted regulations granting blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates. In 2003, the FERC amended the blanket marketing certificates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such matters as natural gas withholding, manipulation of market prices, communication of accurate information and record retention.

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The EPAct contains provisions intended to prohibit the manipulation of the natural gas markets and is applicable to our marketing business as well. See “—LNG Receiving Terminal Business Governmental Regulation—Energy Policy Act of 2005.”

The prices at which we will sell natural gas are not regulated, insofar as the interstate market is concerned and, for the most part, are not subject to state regulation. We are permitted to domestically make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, under “—Natural Gas Pipeline Business—Natural Gas Pipeline Governmental Regulation,” the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

Oil and Gas Exploration and Development Business

Although our focus is primarily on development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and exploitation. Our historical oil and gas exploration activities have existed 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 (see below) whereby the capital costs of such activities are borne primarily by industry partners. Our current oil and gas exploration and development activities have been focused on two areas: the Cameron Project, which covers an area of approximately 230 square miles extending roughly three to five miles on either side of the westernmost 28 miles of Louisiana coastline; and the Offshore Texas Project Area, which covers approximately 6,800 square miles in the shallow waters offshore Texas and the West Cameron Area of offshore Louisiana.

Oil and Gas Exploration and Development Prospects

Our exploration team generated, captured, sold or caused to be drilled 11 prospects during 2005, 2006 and 2007. We retained interests in the form of working interests, overriding royalty interests (a share of the hydrocarbons produced from an oil and gas property, free of the expense of production) and back-in working interests (an agreement whereby we retain a reversion right to a working interest in a well at payout but bear none of the cost of drilling the initial well). Our overriding royalty interests ranged from 0.63% up to 5.0%, and back-in working interests ranged from 15.0% up to 20.0%. We also participated in the drilling of wells with cost-bearing working interests of 5.0% up to 25.0%. In the wells where we participated with a cost-bearing working interest, we also retained an overriding royalty interest prior to payout and a back-in working interest after payout. All 11 of the above-mentioned prospects were drilled by our industry partners.

Oil and Gas Exploration and Development Drilling Activities

During 2005, we participated directly in the drilling of two wells; in 2006, we participated directly in the drilling of four wells; and in 2007, we did not participate directly in the drilling of any wells. Our industry partners drilled three wells, seven wells and one well in 2005, 2006 and 2007, respectively, on prospects that we generated. During 2005, one well was a discovery; during 2006, five wells were discoveries and during 2007, one well was a discovery. For the discoveries drilled in the years 2005 through 2007, four of the wells were producing, one was awaiting development and two were deemed temporarily abandoned.

At December 31, 2007, we had working interests of 5.0% to 25.0% in three wells and overriding royalty interests (ranging from 0.63% to 5.0%) in eighteen other wells. Of the 21 wells in which we had an interest as of December 31, 2007, eleven were productive, one was awaiting development, two were deemed non-commercial, and seven were shut in waiting for plugging and abandonment. All seven of the wells waiting for plugging were wells in which we had only an overriding royalty interest and therefore, we have no liability for abandonment costs.

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Oil and Gas Exploration and Development 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 2005, 2006 and 2007.

Oil and Gas Exploration and Development Acreage

The following table sets forth certain information with respect to our developed and undeveloped leased acreage as of December 31, 2007.

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, 2007 is taken from the report generated by Sharp Petroleum Engineering, Inc., an independent petroleum engineer, in accordance with the rules and regulations of the SEC. The independent engineer’s estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data that we provided.

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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. 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, 2007.

Oil and Gas 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.

Oil and Gas Exploration and Development 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:

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 independent producers of varying sizes, all of which are engaged in the exploration, development and acquisition of producing and non-producing properties.

Oil and Gas Exploration and Development Governmental 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 (“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.

Oil and Gas Exploration and Development Environmental Regulation

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 Business Environmental Regulation” above. In addition, our oil and gas exploration, development and related operations are subject to the following regulations.

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.

The federal Oil Pollution Act of 1990 (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into waters of the U.S. (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, substantially 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 26—“Business Segment Information” of our Notes to Consolidated Financial Statements.

Subsidiaries

Our assets are generally held by or under our operating subsidiaries. We conduct most of our operations through these subsidiaries, including our operations relating to the development of our LNG receiving terminal business, the development of our pipeline business and our marketing business.

Employees

We had 378 full-time employees as of February 15, 2008.

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ITEM 1A. 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. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

Risks Relating to Our Financial Matters

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

From our inception, we have generally incurred operating losses, and we will likely continue to incur operating losses and experience negative operating cash flow through at least 2008. We have incurred, and continue to incur, significant capital and operating expenditures while we develop our planned LNG receiving terminals and pipelines. Although we plan to commence commercial operations of the Sabine Pass LNG receiving terminal during 2008, we do not expect to generate positive operating cash flow from our LNG receiving terminal segment until 2009 at the earliest. Our current oil and gas exploration activities, which are limited in scope, will not generate sufficient funds to cover our 2008 expenditures.

Any delays beyond the expected development periods for our planned LNG receiving terminals or pipelines would prolong, and could increase the level of, our operating losses and negative operating cash flow. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the anticipated timing of receipt of cash flow under TUAs and other sales of capacity in relation to the incurrence of projected project operating expenses. However, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully complete our Sabine Pass LNG receiving terminal and other development projects as well as our ability to commercially exploit Cheniere Marketing’s reserved capacity at the Sabine Pass LNG receiving terminal. Our ability to accomplish these objectives is subject to a number of risks, including those discussed below.

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

As of December 31, 2007, we had $296.5 million in cash and cash equivalents and $770.2 million in restricted cash and cash equivalents and treasury securities, including $420.4 million in restricted cash to be used to complete construction of the Sabine Pass LNG receiving terminal. We will need substantially more financing to complete all of our proposed LNG receiving terminals a natural gas pipelines. In addition, the continued development of our marketing business will require significant credit support and funding. To fund these development projects, we plan to pursue a variety of sources of funding, including some or all of the following:

Our ability to obtain these or other types of financing will depend, in part, on factors beyond our control, such as the status of various debt and equity markets at the time financing is sought and such markets’ view of our industry and prospects at such time. In particular, currently tight lending conditions in the U.S. credit markets

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may make it more time consuming and expensive for us to obtain financing, if we can obtain financing at all. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects are otherwise proceeding on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project sponsor. As a result, even if we are able to identify potential project-level lenders, we may still have to obtain another form of external financing for us to fund an equity capital contribution to the project subsidiary. Any project-level debt financing would likely be conditioned upon our prior receipt of commitments for a portion of projected regasification capacity under long-term TUAs, as well as our achievement of additional milestones. A failure to obtain financing at any point in the development process of any of our projects could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.

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

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

Our substantial indebtedness could adversely affect our ability to operate our business.

As of December 31, 2007, we had approximately $2.8 billion of indebtedness. Our substantial indebtedness could have important consequences, including:

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Our substantial indebtedness and the restrictive covenants contained in our debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business.

Our ability to satisfy our obligations will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. If we are not able to generate sufficient cash from operations to meet our other obligations, we may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

We may experience cost overruns and delays in the completion of our Sabine Pass and other proposed LNG receiving terminals and pipelines as well as difficulties in obtaining funding for any additional costs, which could have a material adverse effect on our financial condition and results of operations.

Our construction costs for Sabine Pass and/or other proposed LNG receiving terminals and pipelines may be significantly higher than our current estimates as a result of cost overruns, change orders under existing or future construction contracts, increased component and material costs, escalating labor costs, limited availability of labor, delays in construction and increased spending to maintain construction schedules. As of February 14, 2008, change orders for $172.7 million had been approved under the EPC agreements with Bechtel and other contractors for the Sabine Pass LNG receiving terminal. We have limited experience constructing LNG receiving terminals.

Furthermore, in order to cover increased construction costs we may need to obtain additional funding. If we fail to obtain sufficient funding, our business plan could fail. Our ability to obtain debt or equity financing that may be needed to provide additional funding to cover increased construction costs will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, results of operations, financial condition and prospects.

Our existing level of cash resources, negative cash flow and limited ability to obtain additional financing could cause us to defer or limit development of our business.

We are dependent upon our existing cash resources, and the availability of additional debt or equity financing, in order to fund our negative operating cash flow and to provide the capital required for the continued development of our business. Prevailing economic and market conditions, as well as other factors, may adversely affect the availability and cost of additional financing, which could require us to defer or limit expenditures we would otherwise make in developing our business. Such deferrals or limitations in the development of our business could be significant and could adversely affect our ability to pursue our business strategy, which in turn could adversely affect our results of operations, financial condition and business prospects.

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Risks Relating to Our LNG Receiving Terminal Business

Our inability to timely construct and commission our LNG receiving terminals would prevent us from commencing operations when anticipated and would delay or prevent us from realizing anticipated cash flows.

We are currently constructing the Sabine Pass LNG receiving terminal. We may not complete the Sabine Pass LNG receiving terminal, and our other LNG receiving terminals, in a timely manner, or at all, due to numerous factors, some of which are beyond our control. Factors that could adversely affect our planned completion include:

Our inability to timely complete the Sabine Pass LNG receiving terminal and our other LNG receiving terminals, as a result of any of the foregoing factors, could prevent us from commencing operations when anticipated, which could delay payments under the TUAs. As a result, we may not receive our anticipated cash flows on time or at all.

We are dependent on Bechtel and other contractors for the successful completion of our LNG receiving terminals.

We have limited experience constructing LNG receiving terminals and working with EPC contractors, including Bechtel, and with other construction contractors. Timely and cost-effective completion of our proposed LNG receiving terminals in compliance with agreed specifications is central to our business strategy and is highly dependent on our contractors’ performance under their agreements with us. Our contractors’ ability to perform successfully under their contracts is dependent on a number of factors, including their ability to:

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Although some of our EPC contracts provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable LNG receiving terminal, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. In addition, each contractor’s liability for liquidated damages is subject to a cap. Each of our material agreements with contractors is also subject to termination by the contractor prior to completion of construction under certain circumstances, including extended delays (of 100 days or more) caused by force majeure events and our insolvency, breach of material obligations not subject to adjustment by change order, or failure to pay undisputed amounts.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the project or result in a contractor’s unwillingness to perform further work on the project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs.

To commission our LNG receiving terminals, we must purchase and process LNG. We have not previously purchased or processed any LNG.

Our LNG receiving terminals must undergo a commissioning process for their storage tanks and other equipment before commencement of commercial operation. The commissioning process will require a substantial quantity of LNG as well as access to adequate LNG tankers to deliver the LNG.

Our construction cost estimates include the costs of acquiring this LNG (a minor portion we refer to as “heel” LNG) at our LNG receiving terminals. Our actual cost to obtain LNG for the commissioning process could exceed our estimates, and the overrun could be significant.

We face several principal risks associated with this required purchase of LNG, including the following:

Our failure to obtain LNG, or our inability to finance the purchase of LNG needed for commissioning, would impede commencement of commercial operation at our LNG receiving terminals, which could delay the date on which our TUA customers are required to begin making payments to us. This delay in payments could have a material adverse effect on our business, results of operations, financial condition and prospects.

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Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminals could impede completion of the terminals and have a material adverse effect on us.

The design, construction and operation of LNG receiving terminals are all highly regulated activities. The FERC’s approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate our proposed LNG receiving terminals. Although we have obtained NGA Section 3 authorization to construct and operate our LNG receiving terminals, such authorization is subject to ongoing conditions imposed by the FERC. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed LNG receiving terminals, including several under the Clean Air Act and the Clean Water Act from the U.S. Army Corps of Engineers and the Louisiana Department of Environmental Quality. We have no control over the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.

After our LNG receiving terminals are placed in service, their businesses will involve significant operational risks.

If we are successful in completing our LNG receiving terminals, we will still face risks associated with operating the facilities. These risks will include, but will not be limited to, the following:

We may be required to purchase natural gas to provide fuel at our LNG receiving terminals, which would increase operating costs and could have a material adverse effect on our results of operations.

The TUAs for regasification capacity at the Sabine Pass LNG receiving terminal provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG receiving terminal, which will be used primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that we will have to purchase additional natural gas from third parties. Sabine Pass LNG has no arrangements in place to obtain any such natural gas and will bear the risk of changing prices with respect to additional natural gas that it may need to purchase for fuel.

We face competition in the LNG receiving terminal business from competitors with far greater resources, as well as potential overcapacity in the LNG receiving terminal marketplace.

Many companies have secured access to, or are pursuing the development or acquisition of LNG import infrastructure to serve the U.S. gas market including major energy corporations (e.g., BG, BP, ExxonMobil, Occidental and ConocoPhillips), industrial corporations, domestic and foreign utilities, and several smaller entrants such as ourselves. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing

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resources and access to LNG supply than we and our affiliates do. The superior resources that these competitors have available for deployment could allow them to compete successfully against us, if and when our TUAs terminate or expire, and/or against Cheniere Marketing, which could have a material adverse effect on us.

Some industry analysts have predicted substantial excess LNG receiving capacity in North America for at least several years based on terminals currently in operation or under construction. This could have a material adverse effect on Cheniere Marketing or on us in the event we have to replace our TUAs, and on our business, results of operations, financial condition and prospects.

We may have difficulty obtaining enough customers for regasification capacity at our proposed LNG receiving terminals to implement and complete our business plan. We may change our business strategy as to how and when we market our capacity.

Our current marketing strategy calls for us to enter into long-term TUAs for a portion of the regasification capacity at our LNG receiving terminals, including a commitment to pay capacity reservation fees, prior to the commencement of construction of each facility. The portion of our total regasification capacity that we plan to commit under such long-term TUAs has changed in the past and may change in the future for various reasons, including responding to market factors or perceived opportunities that we believe may be available to us. Our ability to obtain project-level financing for each LNG receiving facility may be contingent on our ability to enter into commercial agreements in advance of the commencement of construction. As of the date of this filing, we do not have any third-party agreements in place for either our proposed Corpus Christi LNG receiving terminal or our proposed Creole Trail LNG receiving terminal, nor do we have any third-party contracts in place for the use of our pipelines.

We may experience difficulty attracting additional customers because we are a small, developing company with no operating history in the LNG business. In order to succeed, we must convince additional potential customers, among other things, that we will be able to secure adequate financing for the construction of the LNG receiving terminals and natural gas pipelines that we are developing and that they will be approved by appropriate governmental agencies. We may also change our strategy due to our inability to enter into agreements with additional customers prior to construction and based on our views regarding future prices, demand and supply of natural gas and regasification capacity. If these efforts are not successful, our business, results of operations, financial condition and prospects could be materially adversely affected.

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

Sabine Pass LNG has entered into long-term third-party TUAs with Total and Chevron. Each of the TUAs contains various termination rights. For example, each counterparty may terminate its TUA if the Sabine Pass LNG receiving terminal experiences a force majeure delay for longer than 18 months, fails to deliver a specified amount of natural gas redelivery nominations or fails to receive or unload a specified number of LNG cargoes. Sabine Pass LNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated. In the case of each of these TUAs, Sabine Pass LNG is dependent on the respective counterparty’s continued willingness and ability to perform its obligations under the TUAs. If either of these counterparties fails to perform its obligations under its respective TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if Sabine Pass LNG were ultimately successful in seeking damages from that counterparty or its guarantor for a breach of the TUA.

Risks Relating to Our Natural Gas Pipeline Business

Expanding our business by constructing pipelines subjects us to risks.

The construction of a new pipeline involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, through the issuance of additional equity or from operating cash flow. If

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we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Whenever we build a new pipeline, the construction may occur over an extended period of time, and we will not receive any revenues until the pipeline has been completed and customers pay for transportation service on the pipeline. Moreover, we may construct pipelines to capture anticipated future growth in a region in which such growth does not materialize. As a result, our pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The success of our pipeline construction project may depend upon the level of LNG import activity in the areas proposed to be serviced by the project as well as our ability to obtain commitments from LNG suppliers and other customers to utilize the newly constructed pipelines.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our pipelines would have a detrimental effect on us and our LNG projects.

The design, construction and operation of natural gas pipelines and the transportation of natural gas are all highly regulated activities. FERC approval under Section 7 of the NGA, as well as several other material state governmental and regulatory approvals and permits, is required in order to construct and operate our proposed pipelines. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed pipelines, including several under the Clean Air Act and the Clean Water Act from the U.S. Army Corps of Engineers and the Louisiana Department of Environmental Quality. We have no control over the timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our proposed pipelines, including their FERC gas tariffs, will be subject to FERC regulation.

Our FERC tariffs contain pro forma transportation agreements, which must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.

The FERC could change its current ratemaking policies, and those changes could have adverse effects on our proposed pipelines.

Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our proposed pipelines, which would adversely affect our revenues and cash flow.

We will depend upon third-party pipelines and other facilities that will provide delivery options to and from our proposed pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to

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end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our proposed pipelines could have a material adverse effect on our business, results of operations and financial condition.

Our pipeline business could be materially adversely affected if we lose the right to situate our proposed pipelines on property owned by third parties.

We do not anticipate owning the land on which our proposed pipelines will be constructed, and we are subject to the possibility of increased costs to obtain and retain necessary land use. We anticipate obtaining the right to construct and operate our pipelines on land owned by third parties for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be materially adversely affected.

Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.

The federal Office of Pipeline Safety has issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in what the rule refers to as “high consequence areas” where a leak or rupture could potentially do the most harm. The final rule requires operators to:

We will be required to initiate pipeline integrity testing programs that are intended to assess pipeline integrity. The rule, or an increase in public expectations for pipeline safety, may require additional reporting and more frequent inspection or testing of our proposed pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to penalties and fines.

Because our proposed pipelines will be dependent upon a few customers, including an affiliate, for a significant portion of the revenues anticipated to be generated by our pipeline business, our business may be materially and adversely affected if we lose any one of these customers.

We do not currently have any third-party customers for our pipelines. Customers with whom we enter into TUAs for our LNG receiving terminals may enter into agreements for the transportation of revaporized gas on our proposed pipelines. However, the number of such customers is anticipated to be limited, and we anticipate being substantially dependent on them for a significant percentage of the revenues generated by our pipeline business. In addition, the largest customer of our proposed pipelines is anticipated to be our affiliate, Cheniere Marketing, which does not have any arrangements for any supplies of LNG or any unconditional commitments from customers for the purchase of natural gas. The loss of any customers, a decline in their creditworthiness, the failure of Cheniere Marketing to obtain LNG or customers for regasified LNG, or a substantial reduction in customers’ shipments on our proposed pipelines could have a material adverse effect on our business, results of operations and financial condition.

Risks Relating to Our LNG and Natural Gas Marketing Business

We are in the early stages of developing our LNG and natural gas marketing business.

We have recently begun developing our LNG and natural gas marketing business. To date, the business has been unprofitable and has a limited operating history upon which to evaluate our business strategy or the future prospects of the business. Since inception, our LNG and natural gas marketing business has had net operating

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losses. The ability of our LNG and natural gas marketing business to generate revenues in the future will depend upon whether we can successfully develop and implement our business strategy and make the transition from a development stage business to an operating business. We may encounter many expenses, delays, problems and difficulties that we have not anticipated and for which we have not planned in developing and operating our LNG and natural gas marketing business.

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.

To reduce our exposure to fluctuations in the price, volume, timing, location, quality and credit risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on NYMEX and over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:

Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The limited operating history of, and limited capital resources and credit available to, our LNG and natural gas marketing business limit our ability to develop that business.

We have limited the amount of capital available to our LNG and natural gas marketing business. The business currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial, technical and marketing resources and access to LNG supply than we do. Our LNG and natural gas marketing business is in its early stages of development and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business. The limited capital and credit available to our LNG and natural gas marketing business, along with a lack of cash flows, may inhibit our ability to develop that business.

If we do not attract and retain qualified personnel for our developing LNG and natural gas marketing business, our operations could be adversely affected.

Our success in developing and operating an LNG and natural gas marketing business will be, in part, dependent upon the number and quality of personnel that we can hire and our ability to maintain good relationships with them. If we are unable to retain qualified employees and then successfully maintain good relationships with them, our results of operations may be adversely affected.

Our exposure to the performance and credit risks of counterparties under agreements that we have entered into with them may adversely affect our future results of operations and liquidity.

Our LNG and natural gas marketing business enters into purchase and sale, hedging, and other transactions with numerous third parties (commonly referred to as “counterparties”). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our working capital and/or financial results and our access to third-party financing.

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Risks Relating to Our LNG Businesses in General

The inability to import LNG into the United States could materially adversely affect our third-party LNG receiving terminal customers and our business plans and results of operations.

Operation of our LNG receiving terminals and natural gas pipelines will be dependent upon the ability of third-party customers and Cheniere Marketing to import LNG supplies into the United States. Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the United States, may impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the United States. Such foreign suppliers and merchants may also be able to negotiate more favorable prices with other LNG customers around the world than with customers in the United States, thereby reducing the supply of LNG available to be imported into the United States market. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to non-U.S. markets or to competitors’ LNG receiving terminals in the U.S. Any significant impediment to the ability to import LNG into the United States generally or to our LNG terminals specifically could have a material adverse effect on us, on our third-party LNG receiving terminal customers and on our business, results of operations, financial condition and prospects. In addition, the quality of LNG available for importation may not meet the quality specifications of our pipelines or the pipelines interconnected with or downstream of our proposed LNG receiving terminals.

Failure of sufficient LNG liquefaction capacity to be constructed worldwide could adversely affect the performance by our third-party LNG receiving terminal customers and Cheniere Marketing of obligations under TUAs and could reduce our operating revenue and cause us operating losses.

Commercial development of an LNG liquefaction facility takes a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG liquefaction facilities, including:

If sufficient LNG liquefaction capacity is not constructed, our LNG and natural gas marketing business, demand for and development of the assets of our LNG receiving terminal and natural gas pipeline businesses, and our financial performance could each be adversely affected. In addition, our third-party LNG receiving terminal customers may find it difficult to obtain sufficient utilization of their capacity at our LNG receiving terminals to support their obligations under their TUAs.

There may be a shortage of LNG tankers worldwide, which could adversely affect our and our customers’ ability to import LNG into North America and, therefore, inhibit our growth and cause us operating losses.

The construction and delivery of LNG vessels requires significant capital and long construction lead times, and the availability of the vessels could be delayed to our detriment because of:

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Failure of imported LNG to become a competitive source of energy in North America could adversely affect our ability to develop our LNG receiving terminal and natural gas pipeline businesses, our ability to import LNG into North America and our ability to develop our LNG and natural gas marketing business, which could inhibit our growth and cause us operating losses.

In North America, due mainly to a historically abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based, in part, on the belief that LNG can be produced and delivered at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG. In addition to natural gas, LNG also competes in North America with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. In addition, other continents have a longer history of importing LNG and, due to their geographic proximity to LNG producers and limited domestic natural gas supplies, may be willing and able to pay more for LNG, thereby reducing or eliminating the supply of LNG available in North American markets. As a result of these and other factors, LNG may not become a competitive source of energy in North America. The failure of LNG to become a competitive supply alternative to domestic natural gas, oil and other import alternatives could adversely affect our ability to enter into additional TUAs with customers and could also impede the ability to import LNG into North America on a commercial basis and our ability to develop our LNG and natural gas marketing business, which could inhibit our growth and cause us operating losses.

Decreases in the price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect our ability to enter into TUAs and natural gas sale contracts with customers, which could inhibit our growth and cause us operating losses.

The development of domestic LNG receiving terminals and LNG projects generally is based on assumptions about the future price of natural gas and the availability of imported LNG. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

The willingness of potential customers to contract for regasification capacity would be negatively impacted and, once facilities are in operation, LNG throughput volumes would likely decline if the price of natural gas in North America is, or is forecast to be, lower than the cost to produce and deliver LNG to North American

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markets. Any significant decline in the price of natural gas could cause the cost of natural gas produced from imported LNG to be higher than domestically produced natural gas. As a result, we and our customers may not be able to procure supplies of LNG or customers for regasified LNG, which may inhibit our growth and cause us operating losses.

Cyclical or other changes in the demand for LNG regasification capacity may adversely affect our ability to enter into TUAs and natural gas sale contracts with customers, which could inhibit our growth and cause us operating losses.

The economics of our planned LNG terminals, natural gas pipelines and LNG and natural gas marketing operations could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG importation capacity and available natural gas, principally due to the combined impact of several factors, including:

Changes in the economics of our planned LNG receiving terminals, natural gas pipelines and LNG and natural gas marketing operations could materially adversely affect our and our customers’ ability to procure supplies of LNG to be imported into North America and to procure customers for regasified LNG at economical prices, or at all, which could reduce our operating revenues and cause us operating losses.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to retain key personnel could hurt the ability to construct and operate our proposed LNG receiving terminals and pipelines.

Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct our proposed LNG receiving terminals and pipelines and, upon commencement of commercial operation, to provide our customers with the highest quality service. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG receiving terminal construction plan. As a result, we agreed to change orders with Bechtel concerning additional activities and

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expenditures to mitigate the hurricanes’ effects on the construction of the Sabine Pass LNG receiving terminal. Any increase in our operating costs could materially adversely affect our business, results of operations, financial condition and prospects.

Risks Relating to Our Oil and Gas Exploration and Development Business

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 2007 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, including the following:

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, which may be based on production history, results of future development, oil and gas prices, performance of counterparties under agreements to which we are a party and operating and development costs.

Do not interpret the PV-10 values 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.

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Risks Relating to Our Business in General

We have a limited operating history in the LNG businesses that we are developing. Our business plans are contingent on our ability to manage successfully our anticipated expansion and transition to operating these businesses.

We had net losses of $181.8 million and $145.9 million for the years ended December 31, 2007 and 2006, respectively. We expect to continue to incur operating losses and experience negative operating cash flow through at least 2008 and to incur significant capital expenditures through completion of development of the Sabine Pass LNG receiving terminal. Any delays beyond the expected development periods for the Sabine Pass LNG receiving terminal would prolong, and could increase the level of, our operating losses and negative operating cash flows.

We have never managed the construction, operation or maintenance of an LNG facility. We have limited experience in the construction, and no experience in the operation, of LNG receiving terminals or pipelines or the marketing of LNG or natural gas, and, as a result, we will be forced to rely to a significant extent on the new employees we hire to perform these functions. As our operations expand, we will also have to expand our administrative staff. If we are not able to successfully manage the expansion of our business, our business, results of operation, financial condition and prospects could be materially adversely affected.

Our initiatives to pursue downstream and upstream opportunities as part of our overall energy business strategy may not be successful and, even if successful, could expose us to greater and unanticipated risks.

We have little or no prior experience in some of the downstream opportunities that we are pursuing, such as natural gas pipeline development or natural gas marketing. We also have limited experience in some of the upstream opportunities that we are pursuing, such as investment in LNG shipping businesses and oil and gas exploration, development and transportation. Similarly, we have little or no prior experience in other upstream opportunities that we are pursuing, such as securing foreign LNG supply arrangements and developing foreign natural gas reserves that could be converted into LNG and imported into either domestic or international markets. We may not be successful in our efforts to pursue any or all of these initiatives. If we are successful in pursuing one or more of these downstream or upstream opportunities, we will likely incur greater risks than we expect to incur in our LNG receiving terminal business, and some of those risks we will not be able to anticipate.

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

The construction and operation of our proposed LNG receiving terminals and pipelines will be subject to the inherent risks often associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in a significant delay in the timing of commencement of operations and/or 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 or terrorism on our facilities and the facilities and tankers of third parties on which our operations are dependent.

In accordance with customary industry practices, we maintain and intend to maintain insurance against some, but not all, of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition and prospects.

Existing and future governmental regulation could result in increased compliance costs or additional operating costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws and regulations that regulate the discharge of natural gas, hazardous substances, materials and other compounds into the environment or otherwise relate to the protection of the environment. Many of these laws and regulations, such as the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Oil Pollution Act and the

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Clean Water Act, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our LNG receiving terminals and pipelines. Releases in violation of these regulations can lead to substantial liabilities for non-compliance or for pollution or releases of hazardous substances, materials or compounds or otherwise require additional costs or changes in operations that could have a material adverse effect on our business, results of operations, financial condition and prospects. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.

Existing environmental laws and regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us. For example, the adoption of frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers: (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the LNG receiving terminals, this carbon tax may also be imposed on us directly. Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to our LNG receiving terminals through navigable waterways, could cause additional expenditures, restrictions and delays in our business and to the planned construction of our LNG receiving terminals, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have a material adverse effect on our business, results of operations, financial condition and prospects.

Hurricanes or other disasters could result in a delay in the completion of our LNG receiving terminals and pipelines, higher construction costs and the deferral of the dates on which our TUA counterparties are obligated to begin making payments to us.

In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, including windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic damage to coastal and inland areas located in the Gulf Coast region of the U.S. (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern U.S. Construction at the Sabine Pass LNG receiving terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG receiving terminal experienced construction delays and increased costs totaling approximately $36.4 million.

Future similar storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, delays or cost increases in construction of, or interruption of operations at, our LNG receiving terminals, pipelines or related infrastructure.

Terrorist attacks or military campaigns may adversely impact our business.

A terrorist incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed LNG receiving terminals and related natural gas pipelines, which would increase our costs and decrease our cash flows and could delay commencement of commercial operations. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, which, after commencement of commercial operations at our LNG receiving terminals, could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG receiving terminals could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect Cheniere Marketing and our customers, including their ability to satisfy their obligations to us under their TUAs.

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

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements 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.

Some of our economic value is derived from our ownership of a minority interest in an entity over which we exercise no day-to-day control.

We own a 30% limited partner interest in Freeport LNG. Some of our value is attributable to this investment. In this annual report, we may use the words “our,” “we” or “us” in describing this investment or its assets and operations; however, we do not exercise control over Freeport LNG. The management team of Freeport LNG could make business decisions without our consent that could impair the economic value of our investment in Freeport LNG. Any such diminution in the value of our investment could have an adverse impact on our business, results of operations, financial condition and prospects.

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

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy.

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 minority equity interests in Freeport LNG which could be counted as an investment security. We generally plan to invest our liquid assets in commercial paper or other assets that may be considered investment securities in order to achieve higher yields from our available funds than investments in government securities and money market or similar cash investments would provide. Based on our board of directors’ determination of the value of our subsidiaries, we estimate that less than 40% of our assets consist of investment securities. However, in the event we acquire additional investment securities in the future, or if the value of our interests in companies that we do not control were to increase relative to the value of our controlled subsidiaries, we might be required to invest some portion of our liquid assets in government securities or cash items that yield lower returns than our proposed investments, or, in the alternative, we might be required to divest some of our non-controlled business interests, or take other action, in order to avoid being classified as an investment company.

We engage in operations and may make substantial commitments and investments outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.

Conducting operations or making commitments and investments outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations, commitments and investments outside of the United States include risks of:

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Because our reporting currency is the United States dollar, any of our operations conducted outside the United States would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our financial statements.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of December 31, 2007, there were no threatened or pending legal matters that would have a material 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 common stock has traded on the American Stock Exchange under the symbol LNG since March 24, 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 2006 and 2007.

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As of February 15, 2008, we had 48,605,369 million shares of common stock outstanding held by approximately 1,137 record 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 financing agreements, as well as other factors the board of directors deems relevant.

Issuer Purchases of Equity Securities

On May 31, 2007, we announced that we notified Credit Suisse International (“Credit Suisse”) of our irrevocable commitment to exercise, on one or more occasions on or before July 23, 2007, all of our options to purchase from Credit Suisse an aggregate of 9,175,595 shares of our common stock for $35.42 per share. Our option to purchase the shares was part of the issuer call spread entered into in July 2005 by us and Credit Suisse in connection with our issuance of $325.0 million of Convertible Senior Unsecured Notes. As of December 31, 2007, we had acquired 9,175,595 shares of our common stock for a cash price of $35.42 per share under the call options.

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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 OPERATION

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 8, “Financial Statements and Supplementary Data.” This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects:

Overview of Business

We are engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore LNG receiving terminals and natural gas pipelines, and we are also developing a business to market LNG and natural gas. To a limited extent, we continue to be engaged in oil and natural gas exploration and development activities in the Gulf of Mexico. We operate four segments: LNG receiving terminal business, natural gas pipeline business, LNG and natural gas marketing business, and oil and gas exploration and development business. The three LNG receiving terminals under development by us have an aggregate designed regasification capacity of approximately 10.1 Bcf/d, subject to expansion.

LNG Receiving Terminal Business

We have focused our LNG receiving terminal development efforts on the following three projects: the Sabine Pass LNG receiving terminal in western Cameron Parish, Louisiana on the Sabine Pass Channel; the Corpus Christi LNG receiving terminal near Corpus Christi, Texas; and the Creole Trail LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana.

Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Energy Partners, L.P. (“Cheniere Partners”), a Delaware limited partnership, in which we hold an approximate 90.6% interest as a result of the completion of an initial public offering of common units in Cheniere Partners (including

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the exercise by the underwriters of their over-allotment option). In turn, Cheniere Partners owns a 100% interest in Sabine Pass LNG, L.P. (“Sabine Pass LNG”), which is constructing the Sabine Pass LNG receiving terminal. We currently own 100% interests in the proposed Corpus Christi and Creole Trail LNG receiving terminals. In addition, we own a 30% limited partner interest in a fourth LNG receiving terminal project, Freeport LNG, located on Quintana Island near Freeport, Texas. The three LNG receiving terminals under development by us have an aggregate designed regasification capacity of approximately 10.1 Bcf/d, subject to expansion. Sabine Pass LNG has entered into long-term TUAs with Total, Chevron and our wholly-owned subsidiary, Cheniere Marketing, for regasification capacity at the Sabine Pass LNG receiving terminal.

Construction of the Sabine Pass LNG receiving terminal commenced in March 2005, and we anticipate commencing commercial operation during the second quarter of 2008 with initial send out capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf. We anticipate achieving full operability of the Sabine Pass LNG receiving terminal with a total send out capacity of approximately 4.0 Bcf/d and total storage capacity of approximately 16.8 Bcf during the third quarter of 2009. We will contemplate making final investment decisions to complete construction of the Corpus Christi LNG receiving terminal and to commence construction of the Creole Trail LNG receiving terminal upon, among other things, entering into acceptable commercial arrangements and entering into acceptable financing arrangements.

Natural Gas Pipeline Business

We are developing natural gas pipelines to provide access to North American natural gas markets from our LNG receiving terminals, and to serve growing natural gas markets with diverse new sources of natural gas supplies. We have focused our natural gas pipeline development efforts on the following three projects: the Creole Trail Pipeline originating at the Sabine Pass LNG receiving terminal to points of interconnection with multiple interstate and intrastate natural gas pipelines throughout southern Louisiana; the Corpus Christi Pipeline originating at the Corpus Christi LNG receiving terminal to points of interconnect with interstate and intrastate natural gas pipelines in South Texas; and the Cheniere Southern Trail Pipeline originating in southern Louisiana to a point of interconnect with the Florida Gas Transmission Pipeline in Western Florida. We have also purchased an 80% interest in the Frontera Pipeline, a combined transportation and storage project designed to serve industrial and power generation customers in Northeastern Mexico.

In October 2007, the Federal Energy Regulatory Commission (“FERC”) approved an application to merge our Sabine Pass Pipeline into our Creole Trail Pipeline, thereby creating an approximately 150-mile integrated pipeline system, which we refer to as the Creole Trail Pipeline. Initial construction of Phase 1 of the Creole Trail Pipeline (consisting of 94 miles of natural gas pipeline) commenced in the second quarter of 2007, and we anticipate that it will be available for operations in the second quarter of 2008.

The Corpus Christi Pipeline will be developed in conjunction with the Corpus Christi LNG receiving terminal when we have entered into acceptable commercial arrangements and entered into acceptable financing arrangements.

Cheniere Partners has recently completed a non-binding open season to gauge third-party shipper interest in the Cheniere Southern Trail Pipeline project. The pipeline would interconnect with multiple takeaway pipelines from four LNG receiving terminals in Southwestern Louisiana, plus a fifth being developed in Mississippi. The Cheniere Southern Trail Pipeline may also interconnect with multiple onshore pipelines to serve conventional basins in the Gulf of Mexico, and with new developments transporting natural gas from the unconventional shale plays in Texas and Arkansas. The Cheniere Southern Trail Pipeline would supply Florida with natural gas needed to supply the anticipated growth in natural gas-fired generation capacity in the state over the next ten to fifteen years. This pipeline would provide LNG suppliers with access to new natural gas markets, while providing alternative access to conventional gas supplies, to improve gas supply security for Florida and the remainder of the Southeastern U.S.

In September 2007, we entered into an equity purchase agreement with Tidelands Oil & Gas Corporation and acquired an 80% interest in Frontera Pipeline, LLC, an entity which owns 100% of Sonora Pipeline and Terranova Energia, and which together are developing the Burgos Hub Project. The Burgos Hub Project in an

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integrated pipeline project traversing the United States and Mexico border and the construction of a related subterranean storage facility in Mexico. We will contemplate making a final investment decision in the Burgos Hub Project, among other things, receiving all required authorizations to construct and operate the pipeline and storage facility, entering into acceptable commercial arrangements and entering into acceptable financing arrangements for the pipeline and storage facility once operations commence.

LNG and Natural Gas Marketing Business

We are developing a natural gas and LNG marketing and trading business, with a TUA at the Sabine Pass LNG receiving terminal being our principal asset. We intend to build a portfolio of long-term and short-term and spot LNG purchase agreements from foreign suppliers, pursuant to which LNG will be delivered to either our LNG receiving terminals or other terminals with whom we will trade on the supplier’s vessels, or on vessels that we contract for our own use. In order to facilitate the importation of LNG into the U.S., we are also developing a portfolio of downstream natural gas sales agreements with major local distribution companies, power generators, industrial users and other gas marketing firms. We will also purchase domestic natural gas to satisfy our sales commitments during times that we elect to divert contracted supplies away from the U.S., or during times that we are not able to obtain LNG supplies.

As we develop our marketing business, we are engaging in domestic natural gas purchases and sales, transportation and storage transactions, and physical and financial derivative transactions. Through a capacity option agreement, we have obtained the right to deliver LNG to the United Kingdom. In addition, we have contracted for the use of two LNG vessels to transport LNG.

Oil and Gas Exploration and Development Business

Although our focus is primarily on the development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and production activities in the shallow waters of the Gulf of Mexico.

Overview of 2007 Events

Our significant accomplishments during 2007, some of which may also impact future years, include the following:

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Liquidity and Capital Resources

Overview

We are primarily engaged in LNG-related business activities. Most of our revenues will be directly related to our ability to successfully exploit our maritime, LNG receiving terminal, and pipeline assets. As our Creole Trail Pipeline is designed to provide transportation services for our Sabine Pass LNG facility and all of that facility’s throughput capacity is currently contracted for under long-term TUAs, we are dependent on our LNG and natural gas marketing business to provide a significant portion of our revenue until we begin receiving payments under the TUAs with Total and Chevron beginning in 2009. Our LNG and natural gas marketing business activities are not expected to begin to generate significant revenues before the second quarter of 2008, at the earliest.

In March 2007, we formed a publicly traded partnership that includes 100% of Sabine Pass LNG and completed a public offering of common units in the partnership as described below under the caption Cheniere Energy Partners, L.P. We retain a combined general and limited partnership interest of 90.6% in the partnership which is consolidated in our financial statements. As of December 31, 2007 we had $770.2 million in Restricted Cash and Cash Equivalents and U.S. Treasury Securities, including $420.4 million for the remaining construction costs of the Sabine Pass LNG receiving terminal, $212.8 million for interest payments through May 2009 related to the Senior Notes and $75.7 million for cash distributions by Cheniere Partners through the distribution made in respect of the quarter ending June 2009. An additional $61.3 million is restricted under loan and bank guarantee arrangements. We receive unrestricted cash from the partnership through quarterly distributions which are determined by the partnership’s distributable cash balance and are dependent upon our compliance with certain covenants.

We have obtained financing and approval of our board of directors to construct the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline, as more fully described below.

As of December 31, 2007, we had an unrestricted Cash and Cash Equivalents balance of $296.5 million. To execute our current business plan, we will need additional financing in the next 12 months, which we expect to obtain from issuing debt or equity securities, or conducting asset sales or obtaining credit support. However, we may not be able to obtain such financing on terms that are acceptable to us, if at all. See Item 1A. “Risk Factors—Risks Relating to Our Financial Matters.”

Cheniere Energy Partners, L.P.

On March 26, 2007, Cheniere Partners and Cheniere LNG Holdings, LLC (“Holdings”), our wholly-owned subsidiary, completed a public offering of 13,500,000 Cheniere Partners common units (the “Cheniere Partners Offering”). Cheniere Partners received $98.4 million of net proceeds upon the issuance of 5,054,164 common units to the public in the Cheniere Partners Offering, and Holdings received $164.5 million of net proceeds in connection with its sale of 8,445,836 common units of Cheniere Partners. In April 2007, the underwriters of the Cheniere Partners Offering exercised their over-allotment option with Holdings for the purchase of an additional 2,025,000 common units. Holdings received $39.4 million of net proceeds from such sale. The $203.9 million of

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net proceeds received by Holdings was unrestricted as to its use by us while the $98.4 million received by Cheniere Partners was restricted and is invested in U.S. Treasury Securities to fund a distribution reserve. As a result of these transactions, our combined general partner and limited partner ownership interest in Cheniere Partners was reduced to approximately 90.6%.

For each calendar quarter through June 30, 2009, Cheniere Partners will make quarterly cash distributions of $0.425 per unit on all outstanding common units, as well as related distributions to its general partner, using cash and earned interest from the distribution reserve that was funded with the $98.4 million of net proceeds that it received from the Cheniere Partners Offering. From the date of the Cheniere Partners Offering through June 30, 2009, based on our current holdings of approximately 41% of the common units (10,891,357 common units) and 100% of the general partner units (3,302,045 general partner units), we anticipate receiving $4.8 million per quarter out of the total $11.4 million quarterly distribution. After June 30, 2009, the distribution reserve is expected to have been depleted, and Cheniere Partners will rely on the receipt of operating revenues from Sabine Pass LNG’s various TUAs to fund future quarterly cash distributions to us and other unitholders.

In addition to 10,891,357 common units, Holdings, through a wholly-owned subsidiary, also holds 100% of the 135,383,831 subordinated units of Cheniere Partners. These subordinated units were pledged as collateral under the 2007 Term Loan. Holdings’ common, general partner and subordinated units represent an aggregate 90.6% ownership interest in Cheniere Partners. During the subordination period, however, the subordinated units will not be entitled to receive any distributions until the common units have received the initial quarterly distributions plus any arrearages on the initial quarterly distribution from prior quarters. The subordinated units do not accrue arrearages. The subordination period generally will end if: