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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) 659-1361

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

None

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

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

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

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

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $352,000,000 as of June 30, 2004.

26,756,954 shares of the registrant’s Common Stock were outstanding as of February 28, 2005.

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, 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,” “forecast,” “plan,” “project,” “propose” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this annual report.

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Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” beginning on page 29 of this annual report. 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. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

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 “we”, “us” and “our” refer to Cheniere Energy, Inc. and its subsidiaries. We are currently engaged primarily in the business of developing and constructing, and then owning and operating, onshore LNG receiving terminals along the Gulf Coast of the United States. LNG is natural gas that, through a refrigeration process, has been reduced to a liquid state, which represents approximately 1/600th 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 economically justify the use of LNG. LNG is transported using large oceangoing tankers specifically constructed for this purpose. LNG receiving terminals offload LNG from tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market. We are also engaged, to a lesser extent, in oil and natural gas exploration and development activities in the Gulf of Mexico and, through a minority interest in J & S Cheniere S.A., in the chartering and international operation of LNG tankers.

Our common stock has been publicly traded since July 3, 1996 under the name Cheniere Energy, Inc. Our common stock is traded on the American Stock Exchange under the symbol LNG. Our principal executive offices are located at 717 Texas Avenue, Suite 3100, Houston, Texas 77002, and our telephone number is (713) 659-1361. Our internet address is www.cheniere.com.

In this annual report, unless the context otherwise requires:

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Access to Public Filings

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website (located at www.cheniere.com), where we provide a link to the SEC’s website (at www.sec.gov). We make our website content available for informational purposes only. The website should not be relied upon for investment purposes nor is it incorporated by reference into this Form 10-K.

General Development of Business

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

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

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

LNG Receiving Terminal Development

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

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

LNG’s contribution to the North American market has historically been minimal, due mainly to an abundant supply of domestically sourced, low cost natural gas. The EIA has reported, however, that the average wellhead price of natural gas produced in the United States has more than doubled in the last five years, an indication of a declining domestic resource base. Chairman of the Federal Reserve, Alan Greenspan, stated in May 2003 in testimony before Congress that greater access to global natural gas reserves is required for North American natural gas markets “to be able to adjust effectively to unexpected shortfalls in domestic supply [and that] access to world natural gas supplies will require a major expansion of LNG terminal import capacity.”

We believe that LNG is needed as a reliable source of supply to meet demand and that LNG can be delivered to North America at a competitive price.

Our LNG Receiving Terminals

We began developing our LNG receiving terminal business in 1999 and, since then, have been among the first companies to secure sites and commence development of new LNG receiving terminals in the United States. We have focused our initial development efforts on four LNG receiving terminal projects at the following locations: on Quintana Island near Freeport, Texas; in Cameron Parish, Louisiana near Sabine Pass; near Corpus Christi, Texas; and at the mouth of the Calcasieu Channel in Cameron Parish, Louisiana.

Freeport LNG

Development

In 2001, we initiated development of the LNG receiving facility on Quintana Island near Freeport, Texas. In February 2003, we consummated a transaction with entities controlled by Michael S. Smith, or the Smith entities. We contributed to Freeport LNG Development, L.P., or Freeport LNG, all of the interest in the Freeport site and project we had acquired in June 2001 in exchange for a 40% limited partner interest in Freeport LNG and $6.7 million of cash payments. Smith entities owned the general partner interest and the remaining 60% limited partner interest. Smith entities committed to contribute up to $9 million to fund Freeport LNG’s development costs and to apply available proceeds from any sales of options, capacity reservations and loans related to capacity reservations to these costs. In addition, Freeport LNG assumed our obligation to pay to the seller of the lease option for the Freeport site a royalty of, generally, $0.03 per Mcf of gas processed through the Freeport LNG terminal. The minimum royalty is $2 million per year, and the maximum royalty is $11 million per year after production begins. In March 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG. In July 2004, ConocoPhillips Company, or ConocoPhillips, acquired a 50% general partner interest in Freeport LNG from one of the Smith entities, thereby reducing its general partner interest from 100% to 50%. In December 2004, a subsidiary of The Dow Chemical Company, or Dow, acquired a 15% limited partner interest in Freeport LNG from one of the Smith entities, reducing its limited partner interest from 60% to 45%.

As a limited partner in Freeport LNG, we must rely on the general partner to successfully implement Freeport LNG’s business plans. We are generally required to keep economic terms of the Freeport LNG TUAs and other contracts confidential.

The Freeport LNG receiving terminal is being developed on a 233-acre tract of land and is designed with regasification capacity of 1.5 Bcf/d, one dock and two LNG storage tanks with an aggregate LNG storage capacity of 6.7 Bcfe. The unloading dock will be able to handle 78,000 cm to 250,000 cm LNG tankers. We have

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been advised by Freeport LNG that it has entered into a lump-sum turnkey contract for its 1.5 Bcf/d facility and that the estimated cost to construct the facility is approximately $750 million, before financing costs and contingencies. We believe that this cost estimate is subject to change due to such items as cost overruns, change orders and changes in commodity prices.

In January 2005, FERC authorized Freeport LNG to commence construction of the LNG receiving terminal. In order to complete certain phases of the project, Freeport LNG will be required to satisfy remaining conditions specified by FERC. Construction began in the first quarter of 2005, and we currently expect that terminal operations will commence in 2008. We have been advised that Freeport LNG expects to have increases in expenses and debt and increases in contributed capital from the partners as it proceeds with planning, development and construction of the Freeport LNG receiving terminal.

Freeport LNG has advised us that it intends to initiate an application seeking an additional order from FERC that would authorize the construction of an expansion that would substantially increase the capacity at its currently permitted 1.5 Bcf/d Freeport LNG terminal. The anticipated costs, physical description and financing and construction plans for this potential expansion have not been stated by Freeport LNG. These aspects of the development, construction and operation of the Freeport LNG facility, as well as the anticipated financial consequences for us as a limited partner in Freeport LNG, would change as a result of such an expansion from what we are currently able to describe in this annual report.

Dow TUA

In March 2004, Dow entered into a 20-year TUA with Freeport LNG, pursuant to which Freeport LNG is obligated to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. In addition, Freeport LNG will provide for the transportation and delivery of natural gas through the facility’s 9.4-mile pipeline to Stratton Ridge, Texas for interconnection with downstream pipelines. Freeport LNG has no obligation to provide certain services such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats, and (ii) the transportation of natural gas downstream from Stratton Ridge or the construction of any pipelines to provide such transportation.

Dow has reserved 195,275,000 MMbtu of annual LNG receipt capacity under the TUA, which is equivalent to approximately 500 MMcf/d of regasification capacity, assuming an energy content of 1.05 MMBtu per Mcf after adjustment for energy content and gas retention for fuel. The Dow TUA commences between April 2007 and March 2008, runs for an initial term of 20 years from the date on which services commence for Dow at the Freeport LNG facility and is subject to three additional 10-year extensions. Dow is required to pay Freeport LNG a monthly reservation fee for this regasification capacity. In addition, each month Freeport LNG is entitled to retain a percentage of Dow’s share of LNG to be used as fuel at the facility. Dow is also required to pay a portion of power and other operating costs.

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

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

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

ConocoPhillips TUA

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

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

ConocoPhillips has reserved 390,550,000 MMbtu of annual LNG receipt capacity under the TUA, which is equivalent to approximately 1.0 Bcf/d of regasification capacity, assuming an energy content of 1.05 MMBtu per Mcf after adjustment for energy content and gas retention for fuel. The ConocoPhillips TUA commences between April 2007 and March 2008, runs for an initial term until February 2033 and is subject to six additional 10-year extensions. ConocoPhillips is required to pay Freeport LNG a monthly reservation fee for this regasification capacity, which is subject to reduction for any calculated annual shortfalls in available capacity, which are reconciled on both a monthly and an annual basis. In addition, each month Freeport LNG is entitled to retain ConocoPhillips’ allocable share of LNG used as fuel at the facility and its allocable portion of all other actual losses. ConocoPhillips is also required to pay on a monthly basis a portion of power and other operating costs.

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

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

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

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

Funding

Freeport LNG has entered into a credit agreement with ConocoPhillips for ConocoPhillips to provide a substantial majority of the debt financing for the project. To the extent that the funding provided by ConocoPhillips is insufficient or not available to meet the capital expenditures or working capital requirements of Freeport LNG, the general partner of Freeport LNG may obtain such additional funding from any of the following sources:

Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project and other Freeport LNG cash needs generally are to be funded out of Freeport LNG’s own cash flows, borrowings or other sources, and, up to a pre-agreed total amount, with capital contributions by the limited partners. In December 2004 and February 2005, we received notices from the general partner of Freeport LNG stating that its affiliated limited partner’s pre-agreed total capital contributions would be made and that additional capital contributions were being called for from all limited partners to fund a portion of Freeport LNG’s budgeted 2005 expenditures. We presently intend to fund our 30% pro rata share, or approximately $2.5 million, of these capital calls, which cover the period December 2004 through June 2005. Additional capital calls may be made upon us and the other limited partners in Freeport LNG. In the event of each such future capital call, we will have the option either to contribute the requested capital or to decline to contribute. If we decline to contribute, the other limited partners could elect to make our contribution and receive back twice the amount contributed on our behalf, without interest, before any Freeport LNG cash flows are otherwise distributed to us. We currently expect to evaluate Freeport LNG capital calls on a case-by-case basis and to fund additional capital contributions that we elect to make using cash on hand, revenues from advance capacity reservation fees and funds raised through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

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

Pipeline

The Freeport LNG facility includes a 9.4-mile, 36-inch diameter pipeline through which natural gas will be transported to the delivery point at Stratton Ridge, Texas, which is a major point of interconnection with the Texas intrastate gas pipeline grid.

Sabine Pass LNG

Development

We are developing an LNG receiving terminal in Cameron Parish, Louisiana, near Sabine Pass. We formed Sabine Pass LNG, L.P., or Sabine Pass LNG, to develop the terminal. At December 31, 2004, we had options on

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three tracts of land comprising 568 acres in Cameron Parish, Louisiana for the project site. In January 2005, we entered into leases with initial terms of 30 years and which provide for six 10-year optional extensions related to this acreage. In February 2005, two of the three leases were amended, increasing the total acreage under lease to 853 acres.

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

The facility will have two unloading docks that can handle 87,000 cm to 250,000 cm LNG shipping vessels. The cost to construct the Sabine Pass LNG facility is currently estimated at approximately $750 million to $850 million, before financing costs and contingencies. In December 2004, we entered into a lump-sum turnkey agreement with Bechtel, a major international engineering, procurement and construction, or EPC, contractor. Our cost estimate is subject to change due to such items as cost overruns, change orders and changes in commodity prices (particularly steel).

In December 2004, FERC issued an order authorizing Sabine Pass LNG to construct and operate the Sabine Pass LNG receiving terminal, subject to specified conditions that must be satisfied prior to commencement of construction. In February 2005, FERC authorized Sabine Pass LNG to commence soil testing at the site of the LNG receiving terminal. Final FERC authorization to commence construction of the Sabine Pass LNG receiving terminal is expected by early April 2005, with the final notice to proceed, or NTP, expected to be delivered to the EPC contractor promptly thereafter. Terminal operations are anticipated to commence in 2008.

Total TUA

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

Under the TUA, Total has reserved 390,915,000 MMbtu of annual LNG receipt capacity, which is equivalent to approximately 1.0 Bcf/d of regasification capacity, assuming an energy content of 1.05 MMbtu per Mcf and retainage of 2%. The Total TUA is scheduled to commence no later than April 2009, runs for an initial term of 20 years and is subject to six additional 10-year extensions. Beginning on the commercial start date of the Sabine Pass LNG facility, Total has agreed to pay a monthly fixed capacity reservation fee of $9.1 million; and a monthly operating fee of $1.3 million, which is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers). These monthly payment amounts are equivalent to payments of $0.28 per MMbtu for capacity and $0.04 per MMbtu for operating fees, respectively, of reserved monthly LNG receipt capacity. In addition, each month Sabine Pass LNG is entitled to retain 2% of the LNG delivered for Total’s account for use as fuel at the facility. Total’s obligations under the TUA are supported by an irrevocable guarantee in favor of Sabine Pass LNG by Total S.A.

If any governmental authority (i) imposes any taxes on Sabine Pass LNG (excluding taxes on revenue or income) with respect to the services provided under the TUA, or the proposed LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases the costs of Sabine Pass LNG in relation to the services provided or the proposed LNG receiving terminal, Total will bear such taxes or increased regulatory costs at the rate of 40%, subject to adjustment if the LNG regasification facilities are expanded. To the

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extent any ad valorem taxes are imposed and not abated, we will reimburse Total for up to one-half of such amount not to exceed $3.9 million per year.

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

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

Total may terminate the TUA if:

Sabine Pass LNG may terminate the TUA if:

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

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

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10 million will be payable to Sabine Pass LNG pursuant to the Total omnibus agreement upon receiving evidence of the ability to finance construction of the facility, which will be deemed satisfied if an

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acceptable EPC contractor has accepted the NTP with construction. Total has the right to terminate this transaction under the omnibus agreement if these conditions are not satisfied by June 30, 2005. Though non-refundable, these capacity reservation fee payments will be amortized over a 10-year period as a reduction of Total’s regasification capacity tariff under the TUA. As a result, we record the advance payments that we receive as deferred revenue to be amortized to income over the corresponding 10-year period.

Chevron USA TUA

In November 2004, Sabine Pass LNG entered into a TUA with Chevron U.S.A., Inc., or Chevron USA, pursuant to which Sabine Pass LNG is obligated to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at the proposed LNG receiving terminal. Sabine Pass LNG has no obligation to provide certain services such as (i) harbor, mooring and escort services for LNG tankers, including the provision of tugboats, (ii) the transportation of natural gas downstream from the LNG terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

Under the TUA, Chevron USA has reserved 282,761,850 MMbtu of annual LNG receipt capacity, which is equivalent to approximately 700 MMcf/d of regasification capacity, assuming an energy content of 1.085 MMbtu per Mcf and retainage of 2%. The Chevron USA TUA commences between February 2009 and July 2009, runs for an initial term of 20 years and is subject to two additional 10-year extensions. Beginning on the commercial start date of the Sabine Pass LNG facility, Chevron USA is required to pay Sabine Pass LNG a fixed monthly fee for this regasification capacity that is comprised of (i) a reservation fee of $0.28 per MMbtu of one-twelfth of the reserved annual LNG receipt capacity and (ii) an operating fee of $0.04 per MMbtu of one-twelfth of the reserved annual LNG receipt capacity. The operating fee is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers). In addition, each month Sabine Pass LNG is entitled to retain 2% of the LNG delivered for Chevron USA’s account for use as fuel at the facility. ChevronTexaco Corporation will be required to guarantee 80% of Chevron USA’s payment obligations under the TUA.

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

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

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

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

Chevron USA may terminate the TUA if:

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

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

Cheniere, Sabine Pass LNG and Chevron USA simultaneously entered into an omnibus agreement, under which Chevron USA agreed to make advance capacity reservation fee payments. Under the omnibus agreement, Chevron USA has the option, at the same fee, either to reduce its reserved capacity at the Sabine Pass LNG facility to 500 MMcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005.

The omnibus agreement requires Chevron USA to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, beginning with $5 million paid in November 2004 and $7 million paid in December 2004. A third payment of $5 million will be due upon acceptance by Bechtel Corporation, or Bechtel, of the NTP under the EPC agreement. A payment of $3 million will be due if Chevron USA exercises the option to increase its reserved capacity at the Sabine Pass LNG facility to approximately 1.0 Bcf/d. Though non-refundable, these capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity tariff under the TUA. As a result, we record the advance payments that we receive as deferred revenue to be amortized to income over the corresponding 10-year period.

EPC Agreement

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC agreement with Bechtel. Under the EPC agreement, Bechtel will provide Sabine Pass LNG with services for the engineering, procurement and construction of the Sabine Pass LNG receiving, storage and regasification terminal. The work to be performed by Bechtel will include all of the work required to achieve substantial completion and final completion of the Sabine Pass LNG receiving terminal in accordance with the requirements of the EPC agreement, including achieving specified minimum acceptance criteria and performance guarantees. Bechtel is obligated to perform its work in accordance with good engineering and construction practices and applicable laws, codes and standards.

In December 2004 a limited notice to proceed, or LNTP, was issued to and accepted by Bechtel, upon which time Bechtel was required to promptly commence performance of certain off-site engineering and preparatory work under the EPC agreement. Upon its receipt from Sabine Pass LNG of a NTP, Bechtel must commence all other aspects of the work under the EPC agreement. Sabine Pass LNG plans to issue the NTP in April 2005 but may not issue the NTP until:

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Bechtel must achieve substantial completion in accordance with the requirements of the EPC agreement within 1,247 days after delivery of the NTP. Final completion must be attained no later than 90 days after achieving substantial completion.

Until substantial completion under the terms of the EPC agreement, Sabine Pass LNG has certain rights to request change orders, and Bechtel has the right to request change orders up to and after substantial completion in the event of specified occurrences, including, among other things:

Sabine Pass LNG will pay to Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work under the EPC agreement. This contract price is subject to adjustment for changes in certain commodity prices, contingencies, change orders and other items. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to Sabine Pass LNG for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a bonus of $12 million, or a lesser amount in certain cases, if Bechtel, within 1,095 days after delivery of the NTP, completes construction sufficient to achieve, among other requirements specified in the EPC agreement, a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours. In February 2005, a change order for $1.5 million was approved, thereby increasing the total contract price to $648.4 million.

Bechtel warrants in the EPC agreement that:

Until 18 months after substantial completion, Bechtel will be liable to promptly correct any work that is found defective.

In the event of an uncured default by Bechtel, Sabine Pass LNG may terminate the EPC agreement and take any of the following actions:

Following such a termination, if the cost to reach final completion exceeded the unpaid balance of the contract price, Bechtel would be liable for the difference. If the cost to reach final completion were less than the unpaid balance of the contract price, the difference would be payable to Bechtel.

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Sabine Pass LNG also has the right to terminate the EPC agreement for convenience. In the event of any such termination for convenience, Bechtel would be paid:

Sabine Pass LNG may, upon a 30-day written notice to Bechtel, suspend the work under the EPC agreement. In the event of such suspension for a period exceeding 90 consecutive days or 120 aggregate days, other than any suspension due to an event of force majeure or the fault or negligence of Bechtel or its subcontractors, Bechtel would be permitted to terminate the EPC agreement subject to giving a 14 day notice. In the event of such a termination, Bechtel would be entitled to the compensation described above in relation to termination for convenience. If Sabine Pass LNG suspends work under the EPC agreement, Bechtel could be entitled to a change order to recover the reasonable costs of the suspension, including demobilization and remobilization costs. Bechtel may also suspend or terminate the EPC agreement upon the occurrence of certain other events, including force majeure and uncured defaults of Sabine Pass LNG such as:

If Bechtel experiences a force majeure event, it could be entitled to an extension of the date by which substantial completion is to be accomplished and an extension of the date by which it could earn the $12 million bonus. If any force majeure delay lasts at least 30 days, Bechtel would be entitled to an adjustment of the contract price under the EPC agreement to compensate it for its standby expenses, up to a limit of $3.8 million in the aggregate. A force majeure event generally occurs if any act or event occurs that:

Operation

In February 2005, Sabine Pass LNG entered into an Operation and Maintenance Agreement, or O&M Agreement, with Cheniere LNG O&M Services, L.P., or Cheniere O&M, a wholly-owned subsidiary of Cheniere. Pursuant to the O&M Agreement, Cheniere O&M has agreed to provide all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. The O&M Agreement will remain in effect until 20 years after substantial completion of the facility. Prior to substantial completion of the project, Sabine Pass LNG is required to reimburse Cheniere O&M for its operating expenses and pay a fixed monthly fee of $95,000 (indexed for inflation). The fixed monthly fee will increase to $130,000 (indexed for inflation) upon substantial completion of the facility, and Cheniere O&M will be entitled to a bonus equal to 50% of the salary component of labor costs.

In February 2005, Sabine Pass LNG also entered into a Management Services Agreement, or MSA, with Sabine Pass LNG-GP, Inc., or Sabine Pass GP, its general partner and a wholly-owned subsidiary of Cheniere. Pursuant to the MSA, Sabine Pass LNG appointed Sabine Pass GP to manage the business of Sabine Pass LNG,

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excluding those matters provided under the O&M Agreement. The MSA terminates 20 years after the commercial start date set forth in the Total TUA. Prior to substantial completion of construction of the Sabine Pass LNG receiving facility, Sabine Pass LNG is required to pay Sabine Pass GP a monthly fixed fee of $340,000; thereafter, the monthly fixed fee will increase to $520,000 (indexed for inflation).

Funding

On February 25, 2005, Sabine Pass LNG entered into an $822 million senior secured credit facility, or Credit Facility, with a syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC Securities (USA) Inc. serves as collateral agent. The Credit Facility will be used to fund a substantial majority of the costs of constructing and placing into operation the Sabine Pass LNG receiving terminal. Unless Sabine Pass LNG decides to terminate availability earlier, the Credit Facility will be available until no later than April 1, 2009, after which time any unutilized portion of the Credit Facility will be permanently canceled. Before Sabine Pass LNG may make an initial borrowing under the Credit Facility, it will be required to provide evidence that it has received equity contributions in amounts sufficient to fund $216 million of the project costs.

Borrowings under the Credit Facility bear interest at a variable rate equal to LIBOR plus the applicable margin. The applicable margin varies from 1.25% to 1.625% during the term of the Credit Facility. The Credit Facility provides for a commitment fee of 0.50% per annum on the daily committed, undrawn portion of the Credit Facility. Administrative fees must also be paid annually to the agent and the collateral agent. The principal of loans made under the Credit Facility must be repaid in semi-annual installments commencing six months after the later of (i) the date that substantial completion of the project occurs under the EPC agreement and (ii) the commercial start date under the Total TUA. Sabine Pass LNG may specify an earlier date to commence repayment upon satisfaction of certain conditions. In any event, payments under the Credit Facility must commence no later than October 1, 2009, and all obligations under the Credit Facility mature and must be fully repaid by February 25, 2015.

The Credit Facility contains customary conditions precedent to the initial borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass LNG under the Credit Facility are secured by all of Sabine Pass LNG’s personal property, including the Total and Chevron USA TUAs, and the partnership interests in Sabine Pass LNG.