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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.

In connection with the closing of the Credit Facility, Sabine Pass LNG entered into swap agreements with HSBC and Société Générale. Under the terms of the swap agreements, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Credit Facility up to a maximum amount of $700 million. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Credit Facility with respect to hedged drawings under the Credit Facility up to a maximum of $700 million at 4.49% from July 25, 2005 to March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the swap agreements will be March 25, 2012.

Pipeline

FERC issued an order in December 2004 authorizing construction, subject to specified conditions that must be satisfied, of a 16-mile, 42-inch diameter natural gas pipeline designed to transport 2.6 Bcf/d of regasified LNG from the Sabine Pass LNG facility, running easterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas pipelines in southwest Louisiana, including pipelines operated by Natural Gas Pipeline Company of America, Transcontinental Gas Pipeline Corporation and Louisiana Resources Pipeline Company. We believe these existing pipelines are currently capable of transporting approximately 3.8 Bcf/d. It is also possible that one or more other pipeline operators will undertake to build pipeline connections to the Sabine Pass LNG facility. We expect that constructing these pipeline connections will require far less capital and time than the construction of our Sabine Pass LNG facility. Notwithstanding the completion of the foregoing permitting work, we are under no obligation to provide pipeline arrangements from the terminals to downstream

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locations. Our ultimate decisions regarding pipeline connection to the facility will depend upon future developments, including, in particular, customer interest and general market demand for natural gas from the terminal.

Corpus Christi LNG

Development

We are also developing an LNG receiving terminal near Corpus Christi, Texas. We formed Corpus Christi LNG, L.P., or Corpus Christi LNG, in May 2003 to develop the terminal. We contributed our technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus Christi LNG. A third party, BPU LNG, Inc., or BPU LNG, contributed approximately 212 acres of land and easements and committed to contribute cash to fund the first $4.5 million of Corpus Christi LNG project expenses, in exchange for its 33.3% limited partner interest. Corpus Christi LNG also obtained related easements and additional rights to an additional 400 acres. In January 2004, BPU LNG entered into an option agreement with Corpus Christi LNG to acquire 100 MMcf/d of regasification capacity at the terminal, which was subsequently assigned to its sole stockholder, BPU Associates, LLC. In February 2005, we acquired BPU’s 33.3% limited partner interest in exchange for 1 million restricted shares of Cheniere common stock, which we may be required to register pursuant to a piggy-back registration rights agreement in the event that we intend to register our common stock for certain purposes. We will manage the project through the sole general partner interest in Corpus Christi LNG held by our wholly-owned subsidiary.

The Corpus Christi LNG receiving terminal is designed with regasification capacity of 2.6 Bcf/d, two docks and three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcfe. Subject to obtaining financing and an additional order by FERC authorizing construction of an expansion at our Corpus Christi LNG receiving terminal, the facility near Corpus Christi could be expanded from its initial capacity of 2.6 Bcf/d to approximately 3.2 Bcf/d.

The facility will have two unloading docks, which can handle 87,000 cm to 250,000 cm LNG shipping vessels. The cost to construct the Corpus Christi facility is currently estimated at approximately $650 million to $750 million, before financing costs and contingencies. This estimate is based in part on our negotiations regarding a lump-sum turnkey agreement with a major international 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). BPU LNG was required to fund 100% of the first $4.5 million of Corpus Christi LNG’s expenditures, which amount was funded as of March 31, 2004. From that date until February 8, 2005, when we acquired BPU LNG’s 33.3% interest, we funded 66.7% of the expenditures of Corpus Christi LNG, with BPU LNG funding the balance. As the sole owner of Corpus Christi LNG, we will fund or arrange for funding of 100% of expenditures incurred after February 8, 2005.

In December 2003, we submitted to FERC an application for a permit to build the Corpus Christi LNG receiving terminal, as well as a separate but concurrent permit application for its related pipeline. On March 7, 2005, FERC issued the Final Environmental Impact Statement, or FEIS, for our proposed Corpus Christi LNG receiving terminal and our related pipeline. In the FEIS, FERC concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that we will receive, by the second quarter of 2005, an order by FERC authorizing construction of this terminal, which will likely be subject to specified conditions that must be satisfied prior to commencement of construction. We expect to begin construction in the third quarter of 2005 and to commence terminal operations in 2008. The front-end engineering design work for the Corpus Christi LNG terminal has been completed. We expect to engage a major international EPC contractor to perform the EPC work for the facility under a lump-sum turnkey agreement.

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Customers

We have provided detailed information and engaged in preliminary discussions with potential customers and other third parties in an effort to secure long-term TUAs with one or more creditworthy “anchor tenants” for portions of the capacity of our Corpus Christi terminal. Corpus Christi LNG has not yet entered into any TUAs. We are currently marketing 1.0 Bcf/d of capacity under long-term TUAs at $0.32 per MMbtu, the same price contracted for at Sabine Pass LNG. We intend to market the remaining capacity under other long-term, mid-term and/or short-term contracts. However, we may not be able to obtain any TUAs or other contracts for Corpus Christi LNG on terms acceptable to us, or at all.

Funding

We currently expect to be able to fund the costs of the Corpus Christi LNG terminal using project financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, or a combination thereof.

Pipeline

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

Creole Trail LNG

Development

We are also developing an LNG receiving terminal at the mouth of the Calcasieu Channel in Cameron Parish, Louisiana. We formed Creole Trail LNG, L.P., or Creole Trail LNG, in December 2004 to develop the terminal. We have options to lease tracts of land comprising 1,463 acres in Cameron Parish, Louisiana for the project site.

The Creole Trail LNG receiving terminal is anticipated to be designed with regasification capacity of 3.3 Bcf/d, two docks and four LNG storage tanks with an aggregate LNG storage capacity of 13.5 Bcfe. Subject to obtaining financing and an additional order by FERC authorizing construction of an expansion at our Creole Trail LNG receiving terminal, the facility could be expanded from its initial capacity of 3.3 Bcf/d up to approximately 4.0 Bcf/d.

The facility will have two unloading docks, which can handle 87,000 cm to 250,000 cm LNG shipping vessels. The cost to construct the Creole Trail facility is currently estimated at approximately $850 million to $950 million, before financing costs and contingencies. Our cost estimate is preliminary and is subject to change based on negotiating a definitive EPC agreement and other future uncertainties.

In January 2005, we initiated the National Environmental Policy Act, or NEPA, pre-filing process with FERC to obtain an order to commence construction of the facility. Construction is anticipated to begin in the

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third quarter of 2006, and terminal operations are anticipated to commence in 2009, assuming the timely receipt of necessary permits and the entering into of TUAs and other necessary agreements.

Customers

We have engaged in preliminary discussions with potential customers and other third parties in an effort to secure long-term TUAs with one or more creditworthy “anchor tenants” for a portion of our capacity at our Creole Trail terminal. Creole Trail LNG has not yet entered into any TUAs. We anticipate marketing 1.0 Bcf/d of capacity under long-term TUAs at $0.32 per MMbtu, the same price contracted for at Sabine Pass LNG. We intend to market the remaining capacity under other long-term, mid-term and/or short-term contracts. However, we may not be able to obtain any TUAs or other contracts for Creole Trail LNG on terms acceptable to us, or at all.

Funding

We currently expect to be able to fund the costs of the Creole Trail LNG terminal using project financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, or a combination thereof.

Pipeline

In connection with the NEPA pre-filing process, we are seeking approval to construct dual 118 mile, 42-inch diameter natural gas pipelines designed to transport 3.3 Bcf/d of regasified LNG from the site of our proposed Creole Trail LNG receiving terminal, running north/northeasterly along a corridor through six Louisiana parishes where they will terminate near Rayne, Louisiana. The pipelines are anticipated to be designed with potential interconnections to over 15 interstate and intrastate natural gas pipelines in southwest Louisiana. We believe that these existing pipelines are currently capable of transporting approximately 14.0 Bcf/d. Our ultimate decisions regarding pipeline connection to the facility will depend upon future events, including, in particular, customer interest and general market demand for natural gas from the terminal.

Other Sites

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

J & S Cheniere

We hold a minority interest in J & S Cheniere S.A., or J & S Cheniere. The majority interest in J & S Cheniere is held by J & S Energy Holding B.V., or J & S Holding, a Netherlands corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Pursuant to a shareholders agreement, we identify and assist with LNG-related business opportunities that we determine are appropriate for J & S Cheniere. We are not required to offer any particular business opportunities nor funding to J & S Cheniere. All financing of these business opportunities will be provided by J & S Holding should it determine that a business opportunity is appropriate for J & S Cheniere. However, J & S Holding is not required to fund any particular business opportunity. The shareholders agreement gives us the right to purchase additional shares up to a maximum of 50% of the outstanding shares of J & S Cheniere. The shareholders agreement also provides J & S Holding the right to acquire all of our J & S Cheniere shares in the event that we experience a change in control (defined in the stockholders agreement to include a change in a majority of our board, the acquisition of more than 40% of our outstanding common stock other than as approved by our board of directors and a merger or consolidation that results in 50% or less of the surviving entity’s voting securities being owned by the holders of our voting securities immediately prior to such transaction).

As its initial LNG business opportunity, in August 2003, J & S Cheniere chartered its first LNG tanker, the 130,000 cm-capacity Tenaga Empat. In January 2004, J & S Cheniere signed a transportation agreement with

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Sonatrach, the national oil company of Algeria, for the Tenaga Empat to actively transport LNG cargoes into the United States and Europe. Since the agreement terminated in July 2004, the vessel has been operating on a spot charter basis.

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

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

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

Other Energy Business Initiatives

As part of our overall energy business strategy, we are pursuing initiatives that could complement the development of our LNG receiving terminal business. These initiatives include pursuing downstream opportunities such as natural gas pipelines, storage, marketing and trading. In addition, these initiatives include pursuing upstream opportunities such as investment in LNG shipping businesses, securing foreign LNG supply arrangements, development of foreign natural gas reserves that could be converted into LNG, and oil and gas exploration, development, production, transportation and processing activities generally.

Competition

The volume of natural gas supply additions required to meet U.S. consumption needs is a function not only of demand growth, but also the decline in the underlying production base. In North America, this natural decline has been accelerating over the last decade, significantly increasing the need to bring on new supplies. According to a 2003 report by The National Petroleum Council, natural gas production from existing wells in the U.S. in 1991 declined 17%, or 9.0 Bcf/d, by 1992, while natural gas production from existing wells in 2000 declined 27%, or 16.0 Bcf/d, by 2001.

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

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

We compete with other companies to be among the first to construct LNG receiving terminals in economically desirable locations. There are currently over 35 LNG receiving terminals actively proposed to be constructed in the U.S., although we anticipate that only eight will be constructed by 2010. In addition, other companies are pursuing offshore terminals and shipboard regasification facilities to import LNG into U.S. markets.

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

Governmental Regulation

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

FERC

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

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

Freeport LNG

FERC granted Freeport LNG authorization under Section 3 of the NGA to site, construct and operate an LNG receiving terminal and to construct a 9.4 mile pipeline, together with related facilities, in Brazoria County,

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

Sabine Pass LNG/Corpus Christi LNG/Creole Trail LNG

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

Other Federal Governmental Permits, Approvals and Consultations

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

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

Environmental Matters

Our LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. In some cases, these laws and regulations require us to obtain governmental authorizations before we may conduct certain activities or may require us to limit certain activities in order to protect endangered or threatened species or sensitive areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for pollution. As with the industry generally, compliance with these laws increases our overall cost of business. While these laws affect our capital expenditures and earnings, we believe that these regulations do not affect our competitive position in the industry because our competitors are similarly affected by these laws. Environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations. Environmental laws that may affect our operations include:

CERCLA

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

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arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for:

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

Clean Air Act

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

Clean Water Act

Our operations are also subject to the federal Clean Water Act, or CWA, and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. In addition, our operations, including construction of LNG receiving terminals, in areas deemed to be wetlands, or which otherwise involve discharges of dredged or fill material into navigable waters of the United States, may be subject to Army Corps of Engineers permitting requirements.

Hazardous Waste

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

Endangered Species

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

Oil and Gas Exploration and Development

Although our current focus is primarily on the development of an LNG receiving terminal business, we continue to be involved in oil and gas exploration, development and exploitation, and in exploitation of our existing 3D seismic database through prospect generation. We have historically focused on evaluating and

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generating drilling prospects using a regional and integrated approach with a large seismic database as a platform. We expect that our oil and gas exploration activities will continue in the Gulf of Mexico, through active interpretation of our seismic data and generation of prospects, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne by industry partners. Our current oil and gas exploration and development activities are focused on two areas:

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

Cameron Project Seismic Exploration Program

We were formed in 1996 to fund the acquisition of a proprietary seismic database along the transition zone (the area approximately three to five miles on either side of the Gulf of Mexico shore line) in Cameron Parish, Louisiana. Under the terms of an exploration agreement with an industry partner, we paid for certain seismic costs in the amount of approximately $16.5 million and acquired a 50% ownership interest in the seismic data covering the Cameron project, among other interests that have subsequently expired or terminated. After the termination of the exploration agreement, we purchased our partner’s 50% interest in the seismic data for $500,000 and sold all of the seismic data to a seismic marketing company for $3.3 million. We now retain a license to all of the seismic data for use in our exploration program. We are also entitled to receive at no additional cost any subsequent reprocessing of the data, which may be performed by the seismic marketing company.

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

Seismic Exploration Program in Offshore Texas Project Area

In 2000, we acquired two licenses to an aggregate of approximately 1,900 square miles of seismic data from Seitel Data Ltd., a division of Seitel Inc. In October 2000, we exercised our option to expand the agreement with Seitel Data Ltd. to cover an additional 1,900 square miles of seismic data. Together, the licenses acquired from Seitel represent coverage of over 433 Outer Continental Shelf blocks in the shallow waters offshore Texas and Louisiana in the Gulf of Mexico. In 2001, we sold to Gryphon for $3.5 million one of our two licenses to the Seitel 3D seismic data. We retain one license to the Seitel 3D seismic data.

In 2000, we also negotiated a Master Data Users Agreement with a Houston-based firm, Jebco Seismic L.P., to acquire 3,000 square miles (333 blocks) of seismic data in both state and federal waters offshore Texas, bringing our total data set in the shallow waters offshore Texas and Louisiana to approximately 6,800 square miles of seismic coverage. As of December 31, 2003, we had received reprocessed data for the 3,000 square miles of seismic data in the Jebco data set and the 3,800 square miles of seismic data in the Seitel data set, representing all of the reprocessing to be done in the Offshore Texas Project Area. In 2001, we sold to Gryphon for $3.5 million one of our two licenses to the Jebco 3D seismic data covering an additional 3,000 square miles. We retain one license to the Jebco 3D seismic data.

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Our exploration team generated and captured 29 prospects during 2002, 2003 and 2004 and sold interests in 28 of the prospects to industry partners, retaining various overriding royalty interests and working interests ranging from an overriding royalty interest (a share of the hydrocarbons produced from an oil and gas property, free of the expense of production) of less than 1% to a carried working interest (an agreement whereby we retain an interest in a well but bear none or only a portion of the cost of drilling the initial well) of approximately 24%. Nineteen of the prospects sold during 2002, 2003 and 2004 have been drilled by our industry partners, and we expect that several of the remaining prospects sold during that period will be drilled by our industry partners during 2005. However, we do not serve as operator of any of these prospects, and our partners in the prospects are not contractually obligated to drill them.

Drilling Activities

During 2002, 2003 and 2004, we did not participate directly in the drilling of any wells. Our industry partners drilled eight wells, nine wells and two wells in 2002, 2003 and 2004, respectively, on prospects that we generated. During 2002, six of the eight wells were productive; during 2003, seven of the nine wells were productive; and during 2004, both wells were productive. At December 31, 2004, we had a 20% working interest in one well and overriding royalty interests (ranging from 0.7% to 3.7%) in nine other productive wells.

Investment in Gryphon Exploration Company

Cheniere owns 100% of the outstanding common stock of Gryphon. However, after giving effect to the potential conversion of all shares of Gryphon’s convertible preferred stock to shares of Gryphon common stock, we effectively had a 9.3% ownership interest in Gryphon as of December 31, 2004. Although historically we had the ability to exercise significant influence over Gryphon because of our participation on the Gryphon board of directors, we lost the ability to exercise such influence when our representation on Gryphon’s board was reduced to one director in December 2002. As a result, effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting (see Note 8 in the Notes to the Consolidated Financial Statements). Accordingly, no disclosures concerning Gryphon’s 2003 or 2004 activities are included in this Form 10-K.

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

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Production and Sales

The following table presents certain information with respect to our oil and natural gas production, average sales prices received and average production costs during 2002, 2003 and 2004. In April 2002, we sold our interests in the Redfish and Stingray wells on West Cameron Block 49, representing all of our directly-owned producing properties at the time.

Acreage and Wells

The following table sets forth certain information with respect to our developed and undeveloped leased acreage as of December 31, 2004.

At December 31, 2004, we had working interests in one gross (0.2 net) producing gas well; we had overriding royalty interests in nine producing gas wells.

Drilling Activities

All of our drilling activities are conducted through arrangements with independent contractors. We own no drilling equipment. At December 31, 2004, we had a net working interest of 20% in one exploratory gas well.

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Oil and Gas Reserves

All of the information herein regarding estimates of our proved reserves, related future net revenues and PV-10 as of December 31, 2004 is taken from the report generated by Sharp Petroleum Engineering, Inc., our 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.

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

In accordance with SEC guidelines, the estimates of future net revenues from our proved reserves and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. We may receive amounts different than the estimates for a number of reasons, including changes in prices. See Supplemental Information to Consolidated Financial Statements. Estimates of our proved oil and gas reserves were not filed with or included in reports to any other federal authority or agency other than the SEC during the fiscal year ended December 31, 2004.

Business Strategy

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

Seismic Data

We have acquired the following two significant seismic database assets:

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

Analysis and Methodology

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

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

Experience

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

Competition and Markets

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

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

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

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, or MMS, administers. The MMS grants leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to The Outer Continental Shelf Lands Act, or OCSLA. For example, for offshore operations, we must comply with the following MMS requirements:

Bonding and Financial Responsibility Requirements

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

Regulation of Production

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

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

Natural Gas Marketing

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

Environmental Matters

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

NORM

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

Oil Pollution Act

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

Financial Information about Segments

During the last three fiscal years, all of our revenues have resulted from our oil and gas exploration and development activities. For information about our segments’ revenues, profits and losses and total assets, see Note 18 in Notes to Consolidated Financial Statements.

Subsidiaries

Our assets are generally held by or under our wholly-owned operating subsidiaries. We conduct most of our operations through these subsidiaries, including our operations relating to our development of an LNG receiving terminal business.

Employees

We had 63 full-time employees as of February 28, 2005.

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RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. 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 incurred losses, and we will likely continue to incur operating losses and experience negative operating cash flow during the next several years. Although we have begun preliminary engineering work at our Sabine Pass LNG receiving terminal, we have not yet started the construction of any of our planned LNG receiving terminals other than the facility on Quintana Island near Freeport, Texas. We do not anticipate that our LNG receiving operations will generate positive operating cash flow until at least one of our planned facilities is built, which we expect will not be until 2008. Although we may commence operations, revenues under any particular TUA may not commence for up to one year after operations at the related facility commence. We will continue to incur significant capital and operating expenditures while we develop our planned LNG receiving terminals. We do not anticipate that our oil and gas exploration activities, which are limited in scope, or advance sales of regasification capacity at our planned LNG receiving terminals will generate sufficient funds to cover these expenditures. As a result, we expect to continue to have operating losses and negative operating cash flow on a quarterly and an annual basis over the next several years. Any delays beyond the expected development periods for our planned LNG receiving terminals would prolong, and could increase the level of, our operating losses and negative operating cash flow. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully complete our LNG development projects, and our ability to do so is subject to a number of risks, including those discussed below.

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

We currently estimate that the cost of completing the four LNG development projects will exceed $3 billion, before financing costs and contingencies. To fund these development projects, we will have to pursue a variety of sources of financing, including most, if not all, of the following:

Our ability to obtain these types of financing will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects are otherwise proceeding on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project developer. As a result, even if we are able to identify potential project-level lenders, we may still have to obtain another form of external financing for us to fund an equity capital contribution. Any project-level debt financing will also typically be conditioned upon our prior receipt of commitments for a portion of projected regasification capacity under long-term TUAs, and our ability

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to fund the projects will likely be subject to the achievement of additional milestones in our project financing. A failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.

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

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

Risks Relating to Our LNG Receiving Terminal Development Business

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

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

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

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

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

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

Many companies are considering the development of infrastructure in the domestic LNG market, including, without limitation, major oil and gas companies such as ExxonMobil, ConocoPhillips, Royal Dutch/Shell and ChevronTexaco. Other energy companies such as Sempra, Tractebel, McMoRan Exploration, AES, Excelerate Energy and other public and private companies have also proposed LNG receiving facilities, both onshore and offshore. Almost all of our competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do. The superior resources that these competitors have available to deploy could allow them to surpass us in terms of the status of their LNG receiving terminal development projects. Among other things, these competitors may not have to rely on external financing to the same extent we do, if at all.

Industry analysts have predicted that if all of the proposed LNG receiving terminals in North America that have been announced by developers were actually built, there would likely be substantial excess capacity for such terminals in the future. Accordingly, there is a substantial risk that slower-paced LNG receiving terminal development projects may never be completed. Any perception in the LNG receiving terminal marketplace that

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we may be unable to complete our proposed LNG receiving terminals, because competing projects are further along in their development or otherwise, could have a material adverse effect on our business, results of operations, financial condition and prospects.

In addition, our proposed LNG receiving terminals will likely continue to face competition when and if they are completed, including competition from North American sources of natural gas and onshore, offshore and shipboard LNG regasification facilities. If the number of LNG receiving terminals built outstrips demand for natural gas from those terminals, the excess capacity will likely lead to a decrease in the prices that we will be able to obtain for uncommitted amounts of our regasification services. Because of the substantial likelihood that we will have significant debt service obligations, any such price decreases would impact us more severely than our competitors with greater financial resources. Accordingly, potential overcapacity in the LNG receiving terminal marketplace could have a material adverse effect on our business, results of operations, financial condition and prospects.

Cyclical changes in the demand for LNG regasification capacity may result in reduced operating revenues and may cause operating losses in the future.

The economics of LNG terminal 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:

The increases and decreases in the available supply of natural gas as a result of changes in available LNG receiving capacity available could materially adversely affect our business, results of operations, financial condition and prospects.

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

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

The inability to import LNG into the United States due to, among other things, governmental regulation or potential instability in countries that supply natural gas, could materially adversely affect our business plans and results of operations.

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

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

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

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

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

Our current marketing strategy calls for us to enter into long-term TUAs covering a significant portion of the regasification capacity at each of our LNG receiving terminals, including a commitment to pay capacity reservation fees, prior to the commencement of construction of each facility. Our ability to obtain project-level financing for each LNG receiving facility may be contingent on our ability to enter into long-term TUAs covering a significant portion of regasification capacity in advance of the commencement of construction. In addition, we anticipate that we will be able to rely on these capacity reservation fee payments to cover a portion of operating costs prior to commencement of operations at our proposed LNG receiving terminals. As of the date of this filing, we do not have any TUAs in place for either our proposed Corpus Christi facility or our proposed Creole Trail facility.

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

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

Freeport LNG has entered into long-term TUAs with Dow and ConocoPhillips, and Sabine Pass LNG has entered into long-term TUAs with subsidiaries of Total S.A. and ChevronTexaco. Each of the TUAs contains various termination rights. For example, Dow may terminate its TUA during the construction period of the proposed Freeport LNG terminal if it reasonably determines that “substantial completion” of the terminal will not occur prior to a future confidential date. Similarly, ConocoPhillips may terminate its TUA during the construction period of the proposed Freeport LNG terminal if it reasonably determines that the “conversion date” (the date of conversion of construction loans into term loans under the credit facility between Freeport LNG and ConocoPhillips) will not occur prior to a future confidential date. Total has the right to terminate its TUA under an omnibus agreement if specified conditions are not satisfied by June 30, 2005, including evidence of the ability to finance construction of the facility. Total may also terminate its TUA with Sabine Pass if Sabine Pass LNG fails to deliver a specified amount of natural gas nominations or fails to receive or unload a specified number of cargoes. Chevron USA may terminate its TUA with Sabine Pass LNG if Sabine Pass LNG fails or is unable to load a specified number of cargoes scheduled for delivery by Chevron USA during a twelve month period. In addition, in the case of each of our TUAs, we are dependent on the respective counterparties’ creditworthiness and their continued willingness to perform their obligations under the TUAs. If any of these counterparties fails to perform under its respective TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if we were to be ultimately successful in seeking damages from that counterparty for a breach of the TUA.

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

Sabine Pass LNG entered into an EPC agreement in December 2004 with Bechtel. Freeport LNG has advised us that it has entered into a lump-sum turnkey agreement for the construction of its LNG receiving terminal. We also plan to enter into similar types of contracts with a major international EPC contractor for the construction of our proposed Corpus Christi and Creole Trail LNG receiving terminals. The success of our LNG receiving terminal development projects is highly dependent on our ability to enter into acceptable contracts with reputable EPC contractors and for the EPC contractors to perform their obligations under the contracts, including

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completing the projects on a timely basis. However, we may not be able to enter into an acceptable EPC contract for the construction of our proposed Corpus Christi or Creole Trail LNG receiving terminal. In addition, we have no prior experience working with any EPC contractor, including Bechtel. As a result, we may encounter unexpected delays or problems in connection with the construction of any of our proposed LNG receiving terminals. In addition, any EPC agreement could be terminated under certain circumstances prior to completion of construction. For example, see the description of the termination provisions of the EPC agreement with Bechtel under “—Our LNG Receiving Terminals—Sabine Pass LNG—EPC Agreement” above. If our relationship with any initial EPC contractor fails for any reason, we would be forced to engage a substitute contractor, which would likely result in a significant delay in our development schedule and could have a material adverse effect on our business, results of operations, financial condition and prospects.

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

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

Our initiatives to pursue upstream and downstream opportunities as part of our overall energy business strategy may not be successful and, even if successful, could expose use 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 pipelines and storage, marketing and trading. Similarly, we 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, and 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. 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.

Risks Relating to Our Oil and Gas Exploration and Development Business

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

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

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

In order to engage in oil and gas exploration in the areas covered by our 3D seismic data, we must first acquire rights to conduct exploration and recovery activities on such properties. We may not be successful in acquiring farm-outs (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by drilling one or more wells), seismic permits, lease options, leases or other rights to explore for or recover oil and gas. Both the U.S. Department of the Interior and the States of Texas and Louisiana award oil and gas leases on a competitive bidding basis. Non-governmental owners of the onshore mineral interests within the area covered by our exploration program are not obligated to lease their mineral rights to us except where we have already obtained lease options. In addition, other major and independent oil and gas companies with financial resources significantly greater than ours may bid against us for the purchase of oil and gas leases. If we are unsuccessful in acquiring these leases, permits, options and other interests, the area covered by our 3D seismic data that could be explored through drilling will be significantly reduced, and our business, results of operations, financial condition and prospects could be materially adversely effected.

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

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

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

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

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

Our inability to respond appropriately to changes in these factors could have a material adverse effect on our business, results of operations, financial condition and prospects.

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

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

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

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

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

Numerous uncertainties, including those beyond our control, are inherent in estimating quantities of proved oil and gas reserves. Information included herein for 2004 relating to estimates of our proved reserves is based on reports prepared by Sharp Petroleum Engineering, Inc. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows may vary considerably from the actual results because of a number of variable factors and assumptions involved. These include:

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

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

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

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

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

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

Risks Relating to Our Business in General

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

As of February 28, 2005, we had 63 employees, who, for the most part, are focused on the pre-construction stages of the development of our proposed LNG receiving terminals. As we begin construction of the LNG receiving terminals, we will have to hire new onsite employees to manage the construction of each facility. Later,

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

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

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

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

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

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

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

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

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

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transport gas to and from our terminals, which could have a material adverse effect on our business, results of operations, financial condition and prospects. FERC has in the past regulated the prices at which natural gas could be sold. Federal reenactment of price controls or increased regulation of the transport of natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.

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

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

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

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

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

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

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

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fundamental business strategy. We may have to take actions, including buying, refraining from buying, selling or refraining from selling securities or other assets, contrary to what we would otherwise deem to be in our best interest, in order to continue to avoid registration under the Investment Company Act.

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

If we begin conducting operations outside of the United States, our operations may 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 sales and operations outside of the United States include risks of:

Because our reporting currency is the United States dollar, any of our operations 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 charges on our reporting for results from those operations in our financial statements.

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

The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. The continued threat of terrorism and the impact of military and other action will likely lead to continued volatility in prices for natural gas and could affect the markets for the operations of our LNG customers on which we will be dependent. Furthermore, the United States government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. The continuation of these developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.

ITEM 3. LEGAL PROCEEDINGS

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

We received a letter dated December 17, 2004 advising us of a nonpublic, informal inquiry being conducted by the SEC and captioned “In the Matter of Trading in the Securities of Cheniere Energy, Inc.” The SEC requested a chronology, documents and other information, including the names of persons and entities involved

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in or aware of events leading up to our press releases and related Form 8-K filings in November and December 2004, regarding our negotiations and agreements with Chevron USA and our public offering of 5 million shares of common stock. We are cooperating fully with this SEC informal inquiry.

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. Our common stock had previously traded on the American Stock Exchange under the symbol CXY from March 5, 2001 through March 23, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the American Stock Exchange, for each quarter during 2003 and 2004.

As of February 28, 2005, we had 26.8 million shares of common stock outstanding held by approximately 5,200 beneficial owners.

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

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ITEM 6. SELECTED FINANCIAL DATA

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

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

General

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

Freeport LNG

Freeport LNG is developing an LNG receiving terminal with an anticipated regasification capacity of 1.5 Bcf/d. We developed this project and then sold a 60% limited partner interest to an affiliate of the general partner of Freeport LNG and a 10% limited partner interest to another unaffiliated party. We continue to own a 30% limited partner interest in Freeport LNG. Freeport LNG has received authorization from FERC to commence construction of the Freeport LNG facility. 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.

In June 2003, Dow signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal beginning with commercial start-up of the facility expected to occur in 2008. In 2004, Dow entered into a 20-year TUA with Freeport LNG providing for a firm commitment by Dow for the use of 500 MMcf/d of regasification capacity.

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

Sabine Pass LNG

Our 100%-owned limited partnership entity, Sabine Pass LNG, is developing an LNG receiving terminal with an initial regasification capacity of 2.6 Bcf/d. 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 NTP expected to be delivered to the EPC contractor promptly thereafter. Terminal operations are anticipated to commence in early 2008.

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In September 2004, Sabine Pass LNG entered into a TUA to provide Total with approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. In November 2004, Total exercised its option to proceed with the transaction by delivering to Sabine Pass LNG an advance capacity reservation fee payment of $10 million and a guarantee by Total S.A. of certain Total obligations under the TUA. Cheniere, Sabine Pass LNG and Total also entered into an omnibus agreement in September 2004, under which the TUA remains subject to certain conditions described above under “Items 1. and 2. Business and Properties—LNG Receiving Terminal Development—Our LNG Receiving Terminals—Sabine Pass LNG—Total TUA.”

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

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10 million will be payable to Sabine Pass LNG under the Total omnibus agreement upon receiving evidence of the ability to finance construction of the facility, which will be deemed satisfied if an acceptable EPC contractor has accepted the notice to proceed with construction. Total has the right to terminate this transaction under the omnibus agreement if this remaining condition is not satisfied by June 30, 2005.

In November 2004, Sabine Pass LNG entered into a TUA to provide Chevron USA with approximately 700 MMcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. Chevron USA has also agreed to make advance capacity reservation fee payments. The TUA provides for Chevron USA to pay a fee of $0.32 per MMbtu, subject in part to adjustment for inflation, for approximately 700 MMcf/d of regasification capacity for a 20-year period beginning not later than July 1, 2009. Chevron USA has the option, at the same fee, either to reduce its reserved capacity at Sabine Pass to approximately 500 MMcf/d by July 1, 2005 or to increase its reserved capacity to approximately 1.0 Bcf/d by December 1, 2005. ChevronTexaco will guarantee certain Chevron USA payment obligations under the TUA.

Chevron USA is required to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, of which $12 million has been paid. Further advance capacity reservation fee payments are due as described below under “—Liquidity and Capital Resources—LNG Terminal Development—Sabine Pass LNG.”

We estimate that the cost of constructing the 2.6 Bcf/d Sabine Pass LNG facility will be approximately $750 million to $850 million, before financing costs and contingencies. In December 2004, we entered into a lump-sum turnkey agreement with Bechtel at a cost of $646.9 million. Our cost estimate is subject to change due to such items as cost overruns, change orders and changes in commodity prices (particularly steel). In February 2005, a change order for $1.5 million was approved, thereby increasing the total contract price to $648.4 million. 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.

Corpus Christi LNG

We own a 100% limited partner interest in Corpus Christi LNG, which is developing an LNG receiving terminal with a regasification capacity of 2.6 Bcf/d. We are marketing 1.0 Bcf/d of capacity under long-term TUAs of $0.32 per MMbtu, the same price contracted for at Sabine Pass. We intend to market the remaining

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capacity under other long-term, mid-term and/or short-term contracts. However, we may not be able to obtain any TUAs for Corpus Christi on terms acceptable to us at that price, or at all. We currently anticipate that, by the second quarter of 2005, FERC will issue an order authorizing construction of this terminal, which will likely be subject to specified conditions that must be satisfied prior to commencement of construction. Construction is anticipated to begin in the third quarter of 2005, with terminal operations commencing in 2008.

Creole Trail LNG

We own a 100% limited partner interest in Creole Trail LNG. In November 2004, we announced the acquisition of an option on a proposed LNG site at the mouth of the Calcasieu Channel in Cameron Parish, Louisiana, which we refer to as Creole Trail LNG. We plan to develop Creole Trail in the same manner as our Sabine Pass LNG facility, though it will be a larger facility with two docks, four 160,000 cm storage tanks and an initial regasification capacity of 3.3 Bcf/d. We anticipate marketing 1.0 Bcf/d of capacity under long-term TUAs at $0.32 per MMbtu, the same price contracted for at Sabine Pass LNG. We intend to market the remaining capacity under other long-term, mid-term and/or short-term contracts. However, we may not be able to obtain any TUAs for Creole Trail on terms acceptable to us, or at all. In January 2005, we initiated the NEPA pre-filing process with FERC to obtain an order to commence construction of the facility. Construction is anticipated to begin in the third quarter of 2006, with terminal operations commencing in 2009.

Other Activities

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

As part of our overall energy business strategy, we are pursuing additional potential LNG receiving terminal projects, downstream opportunities and upstream opportunities. We are also engaged, to a lesser extent, in oil and gas exploration and development activities in the Gulf of Mexico.

Liquidity and Capital Resources

LNG Terminal Development

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

We own a 30% limited partner interest in Freeport LNG, a 100% limited partner interest in Sabine Pass LNG, a 100% limited partner interest in Corpus Christi LNG and a 100% limited partner interest in Creole Trail LNG. We currently estimate that, in the aggregate, these four terminal projects will require in excess of $3 billion, before financing costs and contingencies, to construct and place in service. In addition, we have related potential pipeline projects in different stages of development. These projects and the other downstream and upstream opportunities we are pursuing, if successfully pursued, will also require significant amounts of capital.

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

As of December 31, 2004, we had working capital of $305.8 million. We must augment our existing sources of cash with significant additional funds in order to carry out our business plan.

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

Freeport LNG

We developed the Freeport LNG project and received cash proceeds of $6.7 million in connection with the disposition in February 2003 of a 60% limited partner interest to an affiliate of the general partner of Freeport LNG (which, in December 2004, sold a 15% limited partner interest to a subsidiary of Dow) and the disposition in March 2003 of a 10% limited partner interest to another unaffiliated party. We retain a 30% limited partner interest in Freeport LNG.

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

Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project 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 covered 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.

Sabine Pass LNG

On February 25, 2005, Sabine Pass LNG entered into an $822 million 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

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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 upon 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.

In connection with the closing of the Credit Facility, Sabine Pass LNG entered into swap agreements with HSBC and Société Générale. Under the terms of the swap agreements, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Credit Facility up to a maximum amount of $700 million. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Credit Facility with respect to hedged drawings under the Credit Facility up to a maximum of $700 million at 4.49% from July 25, 2005 to March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the swap agreements will be March 25, 2012.

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC agreement with Bechtel pursuant to which Bechtel will provide Sabine Pass LNG with services for the engineering, procurement and construction of the Sabine Pass LNG receiving terminal. In December 2004, a LNTP was issued to and accepted by Bechtel, at 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 generally may not issue the NTP until, among other things, it has documented to Bechtel that it has sufficient funds, or has obtained sufficient financing, to pay the amounts required of it under the EPC agreement and it has paid to Bechtel 5% of the contract price, or approximately $32.3 million, as an advance payment.

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.

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

In November 2004, Chevron USA paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $5 million. Chevron USA paid an additional advance capacity reservation fee of $7 million in December 2004. Further advance capacity reservation fees by Chevron USA will also be due under the TUA: $5 million upon confirmation of evidence of the ability to finance construction of the facility, and $3 million if Chevron USA exercises the option to increase its capacity at Sabine Pass to approximately 1.0 Bcf/d. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity tariff under the TUA. As a result, we record the advance payments that we receive, though non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

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

Corpus Christi LNG

We currently estimate that the cost of constructing the Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs and contingencies. The former minority owner was required to fund 100% of the first $4.5 million of Corpus Christi LNG’s expenditures, which amount was reached as of March 31, 2004, and thereafter 33.3%, with us funding the balance. In February 2005, we acquired the minority owner’s interest in Corpus Christi LNG, and from that time forward we will fund or arrange for funding of 100% of Corpus Christi LNG’s expenditures. We currently expect to be able to fund the costs of the Corpus Christi LNG terminal using project financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, or a combination thereof. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.

Creole Trail LNG

We currently estimate that the cost of constructing the Creole Trail LNG facility will be approximately $850 million to $950 million, before financing costs and contingencies. We currently expect to be able to fund the costs of the Creole Trail LNG terminal using project financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, or a combination thereof. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.

Short-Term Liquidity Needs

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

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Historical cash flows

Net cash used in operations totaled $661,000 in 2004 compared to $7.6 million in 2003. The improvement in 2004 primarily resulted from the receipt of $22 million in advance regasification capacity fees related to our Sabine Pass LNG terminal. This amount was more than offset, however, as a result of the expansion of our LNG receiving terminal business. In the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal site, but in subsequent periods, we accelerated the development schedule of our Sabine Pass, Corpus Christi and Creole Trail LNG receiving terminals.

Net cash provided by investing activities was $1.2 million in 2004 as a result of the reimbursement from limited partnership investment, sales of our interests in oil and gas prospects and collection of proceeds from the sale of a limited partnership interest, partially offset by oil and gas property and fixed asset additions, LNG site costs, the purchase of the restricted certificate of deposit and additional capital contributions to Freeport LNG. Net cash provided by investing activities was $30,000 in 2003 as a result of the sale of LNG assets, a limited partnership interest and interests in oil and gas prospects, mostly offset by oil and gas property and fixed asset additions.

Net cash provided by financing activities was $306.7 million in 2004 compared to $8.2 million in 2003. The significant increase in 2004 relates to the completion of our $300 million public equity offering of common stock in December 2004 (before related offering costs of $14.1 million). In addition, we received $20.9 million related to a private sale of our common stock in January 2004 (before offering costs of $965,000) and exercises of warrants and stock options throughout the year. We also received partnership contributions from a minority owner in Corpus Christi LNG. All of the aforementioned were partially offset by debt issuance costs related to our LNG project debt financing and repayments of notes payable. Cash provided by financing activities in 2003 resulted from a private sale of common stock, exercises of warrants and stock options, and partnership contributions by a minority owner in Corpus Christi LNG, partially offset by repayments of notes payable.

Primarily as a result of the aforementioned, our working capital increased to $305.8 million as of December 31, 2004 compared to $155,000 at December 31, 2003.

Issuances of Common Stock

Since our inception, the primary source of financing for our operating expenses, investments in our exploration program and investments in our development of LNG receiving terminals has been the sale of our equity securities. During 2004 and 2003, we raised $305.9 million and $4.4 million, respectively, net of offering costs, from the exchange or exercise of warrants, the exercise of stock options, the public equity offering of common stock and the sale of Cheniere common stock to accredited investors pursuant to Regulation D. Proceeds of the offerings were used for the development of LNG receiving terminals and for general corporate purposes.

We issued a total of 9 million shares of common stock in 2004. In January 2004, we issued 1.1 million shares of common stock in a private placement under Regulation D to twelve accredited investors for total consideration of $14.9 million, or $13.50 per share. We paid a 6.5% sales commission totaling $965,000, resulting in $13.9 million of net proceeds received from the offering. In February 2004, under the 2003 Stock Incentive Plan, 383,000 shares were issued to employees and outside directors in the form of bonus and restricted stock awards related to our performance in 2003. We recorded $2.4 million of non-cash compensation expense in 2004 related to the issuance of 161,000 shares (bonus stock awards) valued at $15.00 per share, which shares were fully vested on the date of grant. In addition, we recorded $3.3 million of deferred compensation as a

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reduction to stockholders’ equity related to the issuance of 222,000 shares (restricted stock awards) valued at $15.00 per share on the grant date that vest on each of the first and second anniversaries of the grant date. In November 2004, 118,176 shares were issued under the 2003 Stock Incentive Plan to employees and outside directors in the form of restricted stock awards related to our performance in 2004. We recorded $4.9 million of deferred compensation as a reduction to stockholders’ equity based on the $41.85 value per share on the date of the grant. One-third of the restricted shares granted in November 2004 vest on each of the first, second and third anniversaries of the grant date. In December 2004, we issued 5 million shares of common stock in connection with a public offering, for which we received net proceeds of $285.9 million. Throughout 2004, we issued a total of 907,916 shares pursuant to the exercise of warrants, resulting in net cash proceeds of $3.4 million. We also issued 1.2 million shares pursuant to the exercise of stock options, resulting in net proceeds of $2.7 million. During 2004, 276,706 shares of our common stock were issued in satisfaction of cashless exercises of stock options and warrants to purchase 195,062 and 125,000 shares, respectively.

We issued a total of 3.2 million shares of common stock in 2003. In April 2003, we issued 750,000 shares of common stock pursuant to a contingent contractual obligation related to Cheniere’s 2001 acquisition of an option to lease the Freeport LNG terminal site. In May 2003, we issued 792,892 shares of common stock to seventeen investors in a private placement made pursuant to Regulation D. The purchase price of the shares included cash of $1.2 million and the surrender of existing warrants to purchase 792,892 shares of our common stock. Offering expenses relating to the private placement were $57,000. In August 2003, we issued 378,308 shares pursuant to a cashless exercise of warrants to purchase 700,000 shares. Throughout 2003, we issued a total of 1.1 million shares pursuant to the exercise of warrants, resulting in net cash proceeds of $2.9 million. We also issued 187,500 shares pursuant to the exercise of stock options, resulting in proceeds of $292,000.

We did not sell any equity securities in 2002.

Contractual Obligations

We are committed to making cash payments in the future on certain of our contracts. We have no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2004 (in thousands).

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

Lease Obligations

In October 2003, we entered into a lease agreement for new office space with a term which runs from December 2003 through April 2014. Beginning in April 2004, our monthly lease rental is $21,000 and escalates to $24,000 beginning in February 2009 through the remaining term of the lease. We have an option to renew the lease for an additional five years at the then-current market rate. In May 2004, we amended our office lease agreement to increase our rentable square footage (the “Expansion Space”). The lease term for the Expansion Space runs from September 2004 through August 2009. Our monthly lease rental for the Expansion Space is

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$14,000 beginning in June 2005. We have the option, subject and subordinate to another tenant’s renewal option, to renew the lease for an additional five years at a rate specified in the amendment. We are also responsible for our proportionate share of the building operating expenses.

In December 2003, we entered an agreement to lease software for use in our exploration activities. This lease provides for annual payments of $230,000 per year to be made prior to the beginning of each contract year. The lease runs through December 31, 2006.

On January 15, 2005, we exercised our Sabine Pass site options and executed 30-year leases related to the option acreage. On February 24, 2005, certain of these leases were amended increasing our total acreage and increasing the annual payments to $1.5 million. We have the option to renew these leases for six 10-year periods.

Restricted Certificate of Deposit and Letter of Credit

Under the terms of our office lease, we are required to post a standby letter of credit in favor of the lessor. The initial amount of the letter of credit was increased from $865,000 to $1.1 million in April 2004 related to the expansion of our office space; and the amount will be reduced by $225,000 per annum over a five-year period. This letter of credit was initially established under the terms of our bank line of credit at that time.

Upon the termination of our bank line of credit in June 2004, we purchased a certificate of deposit in the amount of $1.1 million and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1.1 million. In October 2004, both the letter of credit and certificate of deposit were amended to decrease the face amounts by $225,000 to $898,000. The renewed letter of credit and the certificate of deposit both mature on November 30, 2005. Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit. As a result, the certificate of deposit plus $2,000 of accrued interest is classified as restricted on our balance sheet at December 31, 2004.

Off-Balance Sheet Arrangements

As of December 31, 2004, we had no “off-balance sheet arrangements” that may have a current or future material affect on our consolidated financial condition or results of operations.

Inflation

During 2002, 2003 and 2004, inflation and changing prices have not had any impact on our revenues or income from continuing operations.

Prior Bank Line of Credit

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

Short-Term Promissory Notes

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

In June 2002, we received a $750,000 payment for the sale of options to purchase an aggregate of up to a 20% interest in the Freeport LNG receiving terminal project. The payment was refundable, and repayment was

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secured by a note payable that we executed. In March 2003, an option was exercised and the note payable was canceled.

Exploration Funding

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

Cheniere and Warburg also have the option, in connection with subsequent capital calls made by Gryphon, to contribute up to an additional $75 million to Gryphon, proportionate to their respective ownership interests. Under the terms of the agreement governing these additional contributions, in the event that either we or Warburg elects not to participate in any additional contribution, the other investor has the option to purchase the non-participating investor’s proportionate share. During 2001 and 2002, Gryphon made cash calls totaling $60 million against its capital commitment of $75 million. We declined to participate in such cash calls, and Warburg elected to purchase our proportionate share of such cash calls. As a result, our ownership interest in Gryphon, after the potential effect of converting preferred stock into common stock, was reduced from 36.8% in 2000 to 9.3% in 2002.

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

Seismic Reprocessing

Between June 2000 and October 2000, we acquired licenses to approximately 6,800 miles of seismic data primarily in the shallow waters offshore Texas and also in the West Cameron area in the Gulf of Mexico (the “Offshore Texas Project Area”) in separate transactions with Seitel Data Ltd., a division of Seitel Inc., and Jebco Seismic, L.P. We committed to reprocess all of the data from the Offshore Texas Project Area at a cost of approximately $8.5 million, payable in installments beginning in October 2000 and continuing through the final delivery of reprocessed data, which was received in 2003. We have no existing or contingent liability related to seismic reprocessing as of December 31, 2004.

Results of Operations—Comparison of the Fiscal Years Ended December 31, 2004 and 2003

Overview—Our financial results for the year ended December 31, 2004 reflect a net loss of $24.6 million, or $1.26 per share (basic and diluted), compared to a net loss of $5.3 million, or $0.36 per share (basic and diluted), in 2003.

The major factors contributing to our net loss during 2004 were: LNG receiving terminal development expenses of $17.2 million (which were partially offset by a $2.9 million minority interest in the operations of Corpus Christi LNG) and general and administrative expenses of $12.5 million. These factors were partially offset by a $2.5 million reimbursement from our limited partnership investment in Freeport LNG.

LNG Receiving Terminal Development Activities—LNG receiving terminal development expenses were 156% higher in 2004 ($17.2 million) than in 2003 ($6.7 million). Because we have been in the preliminary stage of developing our LNG receiving terminals, substantially all of the costs to date related to such activities have been expensed. These costs primarily include professional fees associated with front-end engineering and design

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work, obtaining an order from FERC authorizing construction of our terminals and other required permitting for the Sabine Pass LNG, Corpus Christi LNG and Creole Trail LNG receiving terminals and their related natural gas pipelines. The expenses of our LNG employees directly involved in the development of our LNG receiving terminals are also included. LNG receiving terminal development expenses were significantly higher in 2004 because we accelerated, beginning in the third quarter of 2003, the schedule of receiving terminal development for our Sabine Pass and Corpus Christi LNG receiving terminals. We accelerated the development of our Creole Trail LNG receiving terminal in the fourth quarter of 2004.

In 2004, we recorded $5.8 million in terminal development expenses related to the Corpus Christi LNG receiving terminal. This amount was partially offset by $2.9 million related to the minority interest of our 33.3% limited partner. Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4.5 million of project expenditures. As project expenditures had reached $4.5 million by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest. Also during 2004, we incurred direct receiving terminal development expenses of $6.4 million related to our Sabine Pass LNG receiving terminal and $375,000 related to our Creole Trail LNG receiving terminal, in each of which we own 100% of the projects. In addition, during 2004, we incurred $4.8 million in LNG employee-related costs. In connection with the expansion of our LNG receiving terminal business, our employee costs increased, as we expanded our LNG staff from 4 employees during 2003 to an average of 15 employees during 2004. LNG employee-related costs for 2004 also included cash bonuses of $2 million and non-cash compensation of $928,000 (which included unrestricted and restricted stock awards) related to our 2003 and 2004 company performance.

In 2003, we incurred $6.7 million in LNG receiving terminal development expenses. Of this amount, $3 million related to development costs for the Corpus Christi LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner as discussed above. Also during 2003, we incurred $3.7 million primarily for development expenses related to the Sabine Pass LNG project and LNG employee-related costs.

In February 2003, our Freeport LNG receiving terminal project was acquired by Freeport LNG, from whom we retained a 40% limited partnership interest and received payments totaling $5 million over time. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4.8 million. We also sold a 10% interest in Freeport LNG in March 2003 for $2.3 million, resulting in a gain of $423,000. During 2003, we received payments totaling $2.5 million from Freeport LNG, plus $1.7 million in reimbursement of project costs, which were recorded as a reduction to our investment in the partnership. In addition, during 2003 we recorded equity in the 2003 loss incurred by Freeport LNG attributable to our 30% limited partner interest, which reduced our investment basis to zero as of December 31, 2003. In January 2004, we received the final $2.5 million payment from Freeport LNG. Because our investment basis in Freeport LNG had been reduced to zero, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations for 2004.

In 2004, our 30% equity share of the net loss from Freeport LNG was $1.3 million, including $278,000 of loss that was suspended as of December 31, 2003 (see Note 9 to Consolidated Financial Statements). This compares to our equity share of the loss of $4.5 million for 2003. The significant improvement between periods for Freeport LNG was a result of Freeport LNG’s receipt of a non-refundable fee of $10 million from ConocoPhillips in January 2004.

General and Administrative Expenses—General and administrative, or G&A, expenses primarily relate to our general corporate and other activities. These expenses increased $9.9 million, or 391%, to $12.5 million in 2004 compared to $2.5 million in 2003. The increase in G&A resulted primarily from the expansion of our business (including increases in average corporate staff from an average of 5 employees in 2003 to an average of 16 employees in 2004). Corporate employee-related costs for 2004 also included cash bonuses of $2.2 million

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and non-cash compensation of $2.7 million (which included unrestricted and restricted stock awards) related to our 2003 and 2004 company performance. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $1.6 million in 2004 compared to $976,000 in 2003.

Depreciation, Depletion and Amortization Expenses—DD&A expenses increased $895,000, or 209%, to $1.3 million in 2004 from $429,000 in 2003. The increase primarily resulted from higher oil and gas DD&A as a result of an increase in our DD&A rate from $0.98 per Mcfe to $2.48 per Mcfe and higher production volumes discussed below. DD&A also increased as a result of more depreciation expense resulting from the acquisition of furniture, fixtures and equipment associated with the expansion of our business.

Interest and Other Income—Interest and other income increased to $501,000 in 2004 from $3,000 in 2003 primarily because of an increase in our cash balance resulting from our $300 million public equity offering of our common stock in December 2004 (before related offering costs of $14.1 million). In addition, we received $22 million in advance regasification capacity payments in November and December of 2004 and raised $20 million in net cash proceeds related to a private placement of our common stock and exercises of options and warrants to purchase our common stock during 2004.

Oil and Gas Activities—Oil and gas revenues increased by $1.3 million, or 204%, to $2 million in 2004 from $658,000 in 2003 as a result of a 173% increase in production volumes (336,849 Mcfe in 2004 compared with 123,494 Mcfe in 2003) and an 11% increase in average natural gas prices to $5.93 per Mcf in 2004 from $5.33 per Mcf in 2003. We produced from an average of 10 wells in 2004 as compared with an average of 7 wells in 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests, or ORRI, until December 2004. The small amount of production costs in 2004 is attributable to our share of production taxes on two producing wells located in Texas state waters and operating costs attributable to a well converted from an ORRI to a working interest at payout in December 2004.

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

Overview—Our financial results for the year ended December 31, 2003 reflect a net loss of $5.3 million, or $0.36 per share (basic and diluted), compared to a net loss of $5.6 million, or $0.42 per share (basic and diluted), in 2002. The major factors contributing to our loss in 2003 were: LNG receiving terminal development expenses of $6.7 million (which were offset by a $3 million minority interest in the operations of Corpus Christi LNG), our equity share of the loss in Freeport LNG of $4.5 million and general and administrative expenses of $2.5 million. These factors were offset by a $4.8 million gain on the sale of LNG assets and a $423,000 gain on the sale of a limited partnership interest in Freeport LNG.

LNG Terminal Development Activities—Our principal focus in both 2003 and 2002 was the development of LNG receiving terminals. As a result, receiving terminal development expenses represented a major part of our operating costs and expenses for both years. In 2003, we phased out our direct involvement in developing the Freeport, Texas, site, but we accelerated the schedule of receiving terminal development at Sabine Pass, and near Corpus Christi. Accordingly, gross receiving terminal development expenses, before any cost recoveries, were 103% higher in 2003 ($6.7 million) than in 2002 ($3.3 million).

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

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In 2002, we incurred $3.3 million in receiving terminal development expenses for the Freeport LNG receiving terminal. We entered into an agreement in August 2002 to sell a 60% interest in the receiving terminal in exchange for payments to us totaling $5 million over time and payments to others of up to $9 million for expenses, which were already incurred or were to be incurred in connection with the development of the Freeport LNG receiving terminal. During 2002, $1.7 million in such development expenses were charged to the purchaser. This recovery reduced our receiving terminal development expenses reported for 2002 to $1.6 million.

In February 2003, our Freeport LNG receiving terminal project was acquired by Freeport LNG in which we retained a 40% limited partnership interest in addition to the consideration described above. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4.8 million. Furthermore, we sold a 10% interest in Freeport LNG in March 2003 for $2.3 million, resulting in a gain of $423,000. Throughout 2003, we received payments totaling $2.5 million from Freeport LNG, which amounts were recorded as a reduction to our investment in the partnership. In addition, our 30% limited partner interest in the operations of Freeport LNG resulted in our recording equity in the net loss of the partnership of $4.5 million for 2003. This non-cash loss reduced our investment in Freeport LNG to zero.

General and Administrative Expenses—G&A expenses relate to our general corporate and other activities. These expenses increased $624,000, or 33%, to $2.5 million in 2003 compared to $1.9 million in 2002. The principal components of G&A are employee compensation and contracted services, legal fees and travel. We incurred more legal expenses in 2003 in connection with securities compliance filings and increased securities registration costs. We traveled more in 2003 as we increased our profile among the investment community and as we developed an LNG trading venture based in Europe.

Oil and Gas Activities—Oil and gas revenues increased by $419,000, or 175%, to $658,000 in 2003 from $239,000 in 2002 as a result of increased production volumes (123,494 Mcfe in 2003 compared with 94,441 Mcfe in 2002) and increased average natural gas prices of $5.33 per Mcf in 2003 from $2.58 per Mcf in 2002. We had production from an average of seven wells in 2003 as compared with one well in 2002. We incurred no production costs in 2003 because all of our revenues were generated from non-cost bearing ORRI. Production costs in 2002 totaled $90,000 and related to the early months of 2002 before we sold our cost-bearing working interests in oil and gas properties.

Equity in Net Loss of Unconsolidated Affiliate—On January 1, 2003, we began accounting for our interest in Gryphon on the cost method of accounting because we no longer had sufficient board representation to provide us with the opportunity to exert significant influence over the financial and operating policies of the company. In 2002, we accounted for our investment in Gryphon using the equity method of accounting, and our equity share of Gryphon’s losses was $2.2 million.

Other Matters

Critical Accounting Estimates and Policies

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

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Accounting for LNG Activities

Because we have been in the preliminary stage of developing our LNG receiving terminals, substantially all of the costs to date related to such activities have been expensed. These costs primarily include professional fees associated with front-end engineering and design work and obtaining an order from FERC authorizing construction of our terminals and other required permitting for the Sabine Pass LNG, Corpus Christi LNG and Creole Trail LNG receiving terminals and their related natural gas pipelines. Land costs associated with LNG terminal sites are capitalized. Costs of certain permits are capitalized as intangible LNG assets. We have also capitalized costs related to options to purchase or lease land that may be used for potential LNG terminal sites.

Revenue Recognition

LNG regasification capacity fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred.

Full Cost Method of Accounting

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

The costs of our oil and gas properties, including the estimated future costs to develop proved reserves and the carrying amounts of any asset retirement obligations, are depreciated using a composite unit-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs to be amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves (based on current economic and operating conditions), but excluding asset retirement obligations, plus the lower of cost or fair market value of unproved properties, less related income tax effects.

Our allocation of seismic exploration costs between proved and unproved properties involves an estimate of the total reserves to be discovered through our exploration program. This estimate includes a number of assumptions that we have incorporated into a three-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. We transfer unproved properties to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in our exploration program. The carrying value of unproved properties is evaluated for possible impairment by comparing it to the estimated future net cash flows associated with the estimated total reserves to be discovered in our exploration program. To the extent that the carrying value of unproved properties is greater than the estimated future net revenue, any excess is transferred to proved. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate of total reserves to be discovered could affect our capitalization ceiling.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

We account for the retirement of our tangible long-lived assets in accordance with Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 requires

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us to record the fair value of a liability for legal obligations associated with the retirement of tangible long-lived assets and a corresponding increase in the carrying amount of the related long-lived assets. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the unit-of-production method used to depreciate oil and gas properties under the full cost method of accounting.

Oil and Gas Reserves

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

Our proved reserve information included in this annual report for 2004 is based on estimates prepared by Sharp Petroleum Engineering, Inc. Estimates prepared by others may be higher or lower than our estimates.

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

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

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

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, that addresses the accounting for share-based payment transactions in which a company receives employee services in exchange for equity instruments of the company, such as stock options and restricted stock. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using the APB Opinion No. 25 and requires instead that such transactions be accounted for using a fair value-based method. We currently account for stock-based compensation using the intrinsic method pursuant to APB Opinion No. 25. SFAS No. 123R requires that all stock-based payments to employees, including grants of employee stock options and restricted stock, be recognized as compensation expense in the financial statements based on their fair values. SFAS No. 123R will be effective for periods beginning after June 15, 2005. Accordingly, we will be required to apply SFAS No. 123R beginning in the fiscal quarter ending September 30, 2005. We are currently assessing the provisions of SFAS No. 123R and its impact on our consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

We produce and sell natural gas, crude oil and condensate. As a result, our financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. We had not entered into any derivative transactions as of December 31, 2004.

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital, and such cash investments are stated at historical cost which approximates fair market value on our consolidated balance sheet.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Cheniere Energy, Inc.:

We have audited the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Freeport LNG Development, L.P. (“Freeport LNG”), an investment which, as discussed in Note 9 to the consolidated financial statements, is accounted for by the equity method of accounting. The investment in Freeport LNG was ($1,071,000) and zero as of December 31, 2004 and 2003, respectively, and the equity in its net loss was $1,346,000, $4,471,000 and zero, respectively, for each of the three years in the period ended December 31, 2004. We also did not audit the financial statements of Gryphon Exploration Company (“Gryphon”), an investment which, as discussed in Note 8 to the consolidated financial statements, has been, until January 1, 2003, accounted for by the equity method of accounting. The investment in Gryphon was zero as of December 31, 2004 and 2003, and the equity in its net loss was zero, zero and $2,185,000, respectively, for each of the three years in the period ended December 31, 2004. The financial statements of Freeport LNG and Gryphon were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Freeport LNG and Gryphon, are based solely on the reports of the other auditors.

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

In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Cheniere Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.