For The Quarterly Period Ended March 31, 2005

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes x No ¨.

As of May 2, 2005, there were 53,745,150 shares of Cheniere Energy, Inc. Common Stock, $.003 par value, issued and outstanding.

This quarterly 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 (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (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 quarterly report.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” of our annual report on Form 10-K, as amended, for the year ended December 31, 2004. 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 quarterly 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.

The unaudited consolidated financial statements of Cheniere Energy, Inc. have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation have been included. As used herein, the terms “Cheniere,” “we,” “our,” and “us” refer to Cheniere Energy, Inc. and its subsidiaries.

For further information, refer to the consolidated financial statements and footnotes included in our annual report on Form 10-K, as amended, for the year ended December 31, 2004. Interim results are not necessarily indicative of results to be expected for the full fiscal year ending December 31, 2005. Certain reclassifications have been made to conform prior period amounts to the current period presentation. These reclassifications had no effect on net loss or stockholders’ equity.

All references to issued and outstanding shares, weighted average shares, and per share amounts in the accompanying unaudited consolidated financial statements have been retroactively adjusted to reflect our two-for-one stock split that occurred on April 22, 2005.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“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 non-vested stock. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using the Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, 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 non-vested stock, be recognized as compensation expense in the financial statements based on their fair values. SFAS No. 123R was scheduled to be effective for periods beginning after June 15, 2005. However, on April 14, 2005, the SEC deferred the effective date to January 1, 2006 for companies with fiscal years ending December 31. Accordingly, we will be required to apply SFAS No. 123R beginning in the fiscal quarter ending March 31, 2006. We are currently assessing the provisions of SFAS No. 123R and its impact on our consolidated financial statements.

We account for employee stock-based compensation granted under our long-term incentive plans using the intrinsic value method prescribed by APB Opinion No. 25 and related interpretations. Stock-based compensation expense associated with option grants was not recognized in the net loss for the three month periods ended March 31, 2005 and 2004, as all options granted had exercise prices equal to the market value of the underlying common stock on the dates of grant. The following table illustrates the effect on the net loss and the net loss per share if we had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation:

On February 25, 2005, Sabine Pass LNG, L.P., our wholly-owned subsidiary (“Sabine Pass LNG”), entered into an $822,000,000 credit agreement and other related agreements (the “Sabine Pass Credit Facility”) with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC Bank USA, N.A. (“HSBC”) serves as collateral agent. Under the terms and conditions of the Sabine Pass Credit Facility, all cash held by Sabine Pass LNG is controlled by the collateral agent. These funds can only be released by the collateral agent upon receipt of satisfactory documentation that the Sabine Pass LNG project costs are bona fide expenditures and are permitted under the terms of the Sabine Pass Credit Facility. The Sabine Pass Credit Facility does not permit Sabine Pass LNG to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, our total cash balance of $1,760,000 held in these accounts as of March 31, 2005 is classified as restricted on our balance sheet.

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 $1,123,000 in April 2004 related to the expansion of our office space, and the amount will be reduced $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 $1,123,000 and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1,123,000. 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, respectively. 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 accrued interest is classified as restricted on our balance sheet at March 31, 2005 and December 31, 2004.

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC contract with Bechtel Corporation (“Bechtel”). Under the EPC contract, we were required to make a 5% advance payment to Bechtel upon issuance of the final Notice to Proceed (“NTP”) related to the construction of the Sabine Pass LNG facility. A payment of $32,347,000 was made to Bechtel on March 28, 2005 when the NTP was issued and is classified on our consolidated balance sheet as a current asset. This amount will be reclassified to construction-in-progress over the next twelve months in accordance with the payment schedule included in the EPC contract.

Property, plant and equipment is comprised of investments in oil and gas properties, LNG terminal construction-in-progress expenditures, LNG site and related costs, and fixed assets (in thousands):

As of March 31, 2005, we had incurred $17,939,000 of costs directly associated with arranging debt financing, net of accumulated amortization. Of this amount, $17,059,000 was incurred for the Sabine Pass Credit Facility, which closed February 25, 2005. In March 2005, we began amortizing the costs associated with the Sabine Pass Credit Facility over the ten-year term of the facility. The amortized cost is being capitalized as construction-in-progress during the construction period for the Sabine Pass LNG receiving terminal and will be expensed as interest expense when the terminal is in service. For the three months ended March 31, 2005, the amount amortized and capitalized was $141,000.

In addition, as of March 31, 2005, we had incurred $970,000 of costs directly related to our planned offering of senior notes in a private debt placement. In the event it is determined that the senior notes are not to be issued, we will charge this amount to expense.

We account for our 30% limited partnership investment in Freeport LNG Development, L.P. (“Freeport LNG”) using the equity method of accounting. For the three months ended March 31, 2004, our equity share of net income in the limited partnership was $2,155,000. This amount includes a reduction of $278,000 related to our equity share of the net loss of the partnership not recorded in 2003 because our investment in the limited partnership at December 31, 2003 had been reduced to zero, and we had no obligation or commitment to fund this unrecorded loss. For the three months ended March 31, 2005, our equity share of the net loss of the limited partnership was $844,000.

In January 2004, we received a $2,500,000 payment from Freeport LNG. Because our investment basis in Freeport LNG had been reduced to zero as of December 31, 2003, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations.

In December 2004 and February 2005, we received capital call notices totaling $2,491,000 from Freeport LNG related to the funding of our 30% share of forecasted partnership expenditures from December 2004 through June 2005. During December 2004 and the first quarter of 2005, we funded $275,000 and $1,134,000, respectively, of such capital calls.

As of March 31, 2005 and December 31, 2004, our investment balances in Freeport LNG were zero, and we had accrued losses on investment in limited partnership of $780,000 and $1,071,000, respectively. We accrued this liability because we presently intend to provide additional financial support through the capital calls as described above.

The financial position of Freeport LNG at March 31, 2005 and December 31, 2004, and the results of Freeport LNG’s operations for the three months ended March 31, 2005 and 2004, are summarized as follows (in thousands):

In connection with the closing of the Sabine Pass Credit Facility on February 25, 2005, we entered into interest rate swap agreements with HSBC and Société Générale (the “Swaps”) to hedge against changes in floating interest rates. Under the terms of the Swaps, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Sabine Pass Credit Facility up to a maximum amount of $700,000,000. The Swaps have the effect of fixing the LIBOR component of the interest rate payable under the Sabine Pass Credit Facility with respect to hedged drawings under the Sabine Pass Credit Facility up to a maximum of $700,000,000 at 4.49% from July 25, 2005 through March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the Swaps will be March 25, 2012.

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments. Under SFAS No. 133, we are required to record derivatives on our balance sheet as either an asset or liability measured at their fair value, unless exempted from derivative treatment under the normal purchase and normal sale exception. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met. These criteria require that the derivative is determined to be effective as a hedge and that it is formally documented and designated as a hedge.

We have determined that the Swaps qualify as cash flow hedges within the meaning of SFAS No. 133 and have designated them as such. At their inception, we determined the hedging relationship of the Swaps and the Sabine Pass Credit Facility to be highly effective using the cumulative dollar offset method. We will continue to assess the hedge effectiveness of the Swaps on a quarterly basis in accordance with the provisions of SFAS No. 133.

SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income (“OCI”) and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. If the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in OCI is recognized currently in earnings.

The following table reflects the amounts that are recorded as assets and liabilities at March 31, 2005, for our derivative instruments (in thousands):

From our inception, we have recorded losses for both financial reporting purposes and for federal income tax reporting purposes. Accordingly, we are not presently a taxpayer, and therefore there is no tax effect on comprehensive income.

Below is a reconciliation of our net derivative assets to our accumulated other comprehensive income, net of tax, at March 31, 2005 (in thousands):

As of March 31, 2005, we have not realized any actual earnings or losses as a result of our hedging activity. The maximum length of time over which we have hedged our exposure to the variability in future cash flows for forecasted transactions is seven years under the Swaps. We estimate that pre-tax losses of $104,000 will be reclassified from OCI into earnings during the year ended December 31, 2005, as the hedged transactions affect earnings, assuming constant interest rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that interest rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next nine months.

On February 8, 2005, we acquired the minority interest of Corpus Christi LNG, L.P. (“Corpus Christi LNG”) through the acquisition of BPU LNG, Inc. (“BPU”) in exchange for 2,000,000 restricted shares of our common stock. BPU held as its sole asset the 33.3% limited partner interest in Corpus Christi LNG. As a result of this transaction, we now own 100% of the limited partner interests of Corpus Christi LNG. This transaction was accounted for using the purchase method of accounting as prescribed by SFAS No. 141, Accounting for Business Combinations, and was valued at $77,239,000, including direct transaction costs. Of this amount, $76,924,000 has been recorded as goodwill and will be accounted for in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. The goodwill is the difference between the deemed value of the shares conveyed and the historical carrying value of the minority interest under generally accepted accounting principles plus direct transaction costs. Goodwill is subject to an annual goodwill impairment review, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate that the carrying value may not be recoverable.

Because BPU’s sole asset was the 33.3% limited partner interest in Corpus Christi LNG, which was consolidated in our financial statements, we do not believe that pro forma financial statements would provide any additional benefit to an investor in our common stock. As a result, we have not prepared pro forma financial statements related to the transaction.

In December 2003, we entered into an option agreement with J & S Cheniere S.A., a Switzerland joint-stock company (“J & S Cheniere”), an entity in which we are a minority owner under which J & S Cheniere has an option to enter into a TUA reserving up to 200 million cubic feet per day (“MMcf/d”) of capacity at each of our Sabine Pass and Corpus Christi LNG facilities. We were paid $1,000,000 in connection with the execution of the option agreement by J & S Cheniere in January 2004. The terms of the TUA contemplated by the J&S Cheniere option agreement have not been negotiated or finalized. We anticipate that definitive arrangements with J & S Cheniere may involve different terms and transaction structures than were contemplated when the option agreement was entered into in December 2003. We have recorded the option fee as deferred revenue.

In November 2004, Total LNG USA, Inc. (“Total”) paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $10,000,000 in connection with the reservation of approximately 1.0 billion cubic feet per day (“Bcf/d”) of LNG regasification capacity at the Sabine Pass LNG receiving terminal. An additional advance capacity reservation fee payment of $10,000,000 was paid by Total to Sabine Pass LNG in April 2005. The advance capacity reservation fee payments will be amortized over a 10-year period after operations commence as a reduction of Total’s regasification capacity fee under its TUA. As a result, we record the advance capacity reservation payments that we receive, though non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

Also in November 2004, we entered into a TUA to provide Chevron USA, Inc. (“Chevron USA”) with approximately 700 MMcf/d of LNG regasification capacity at our Sabine Pass LNG receiving terminal. Chevron USA has the option either to reduce its 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. A related omnibus agreement requires Chevron USA to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20,000,000, beginning with $5,000,000 paid in November 2004 and $7,000,000 paid in December 2004. A third payment of $5,000,000 was paid by Chevron USA to Sabine Pass LNG in April 2005. A payment of $3,000,000 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. These

capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity fee under the TUA. As a result, we record the advance capacity reservation payments that we receive, though non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

As of March 31, 2005 and December 31, 2004, we had recorded $23,000,000 as deferred revenue related to option and advance capacity reservation fee payments.

In May 2003, we formed Corpus Christi LNG to develop an LNG receiving terminal near Corpus Christi, Texas. Under the terms of the limited partnership agreement, we contributed our technical expertise and know-how and all of the work in progress related to the Corpus Christi LNG project, in exchange for a 66.7% limited partnership interest in Corpus Christi LNG. We also manage the project as the general partner through one of our wholly-owned subsidiaries.

For the three months ended March 31, 2005 and 2004, the consolidated statement of operations includes $97,000 and $1,482,000, respectively, related to the minority interest of Corpus Christi LNG. Substantially all Corpus Christi LNG 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 $4,500,000 of partnership expenditures. As partnership expenditures had reached $4,500,000 as of March 31, 2004, the minority owner began sharing all subsequent expenditures based on its 33.3% limited partner interest.

On February 8, 2005, we acquired the minority interest of Corpus Christi LNG through the acquisition of BPU. As a result of this transaction, we now own 100% of the limited partner interests of Corpus Christi LNG.

On February 25, 2005, Sabine Pass LNG entered into the $822,000,000 Sabine Pass Credit Facility with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC serves as collateral agent. The Sabine Pass 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 Sabine Pass Credit Facility will be available until no later than April 1, 2009, after which time any unutilized portion of the Sabine Pass Credit Facility will be permanently canceled. Before Sabine Pass LNG may make an initial borrowing under the Sabine Pass 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. As of March 31, 2005, there were no borrowings outstanding under the Sabine Pass Credit Facility.

Borrowings under the Sabine Pass 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 Sabine Pass Credit Facility. The Sabine Pass Credit Facility provides for a commitment fee of 0.50% per annum on the daily committed, undrawn portion of the facility. Administrative fees must also be paid annually to the administrative agent and the collateral agent. Principal and interest payments are to be made in semi-annual installments commencing six months after the latter of (i) the date that substantial completion of the project occurs under the EPC contract 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 Sabine Pass Credit Facility must commence no later than October 1, 2009, and all obligations under the Sabine Pass Credit Facility mature and must be fully repaid by February 25, 2015.

The Sabine Pass Credit Facility contains customary conditions precedent to the initial borrowing and any subsequent borrowings as well as customary affirmative and negative covenants. Sabine Pass LNG has obtained and may in the future seek consents, waivers and amendments to the Sabine Pass Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass 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 January 2004, we repaid the $1,000,000 outstanding balance under a line of credit with a commercial bank. The line of credit was terminated in June 2004.

Basic net loss per share is computed by dividing the net loss by the weighted average number of common shares outstanding for the period. The computation of diluted net loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to net income were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of Cheniere.

The following table is a reconciliation of the basic and diluted weighted average shares outstanding for the three months ended March 31, 2005 and 2004 (in thousands):

The following table is a reconciliation of our Net Loss to our Comprehensive Loss for the periods shown (in thousands):

On January 15, 2005, we exercised our Sabine Pass LNG site options and executed 30-year leases related to the option acreage. On February 24, 2005, certain of these leases were amended, thereby increasing our total acreage and increasing the annual payments to $1,500,000. We have the option to renew these leases for six 10-year periods.

On March 30, 2005, we amended our office lease to increase our rentable square footage to include an additional floor on the premises. The lease term for the additional floor runs from May 2005 through January 2014. We have an option to renew the lease for an additional five years at the then-current market rate as part of the renewal of our original lease space. Under the amended lease, we have no monthly lease rental for the additional floor from May 2005 through April 14, 2007, after which time it ranges from approximately $30,000 to $39,000 per month through January 2014. We have prepaid $201,000 in rent related to 2013 and have included such amount in other assets on the accompanying consolidated balance sheet as of March 31, 2005.

Our business activities are conducted within two principal operating segments: LNG receiving terminal development and oil and gas exploration and development. These segments operate independently.

Our LNG receiving terminal segment is in various stages of developing LNG receiving terminal projects along the U.S. Gulf Coast, primarily 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.

Our oil and gas exploration and development segment explores for oil and natural gas using a regional database of 7,000 square miles of regional 3D seismic data. Exploration efforts are focused on the shallow waters of the Gulf of Mexico offshore of Louisiana and Texas and consist primarily of active interpretation of our seismic data and generation of prospects, participation in the drilling of wells and 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. This segment participates in drilling and production operations with industry partners on the prospects that we generate.

During April 2005, we issued 166,666 shares of common stock pursuant to the exercise of stock options at an average price of $0.92 per share, which generated proceeds of $154,000.

A limited notice to proceed (“LNTP,”) was issued to and accepted by Bechtel in December 2004, at which time Bechtel was required to promptly commence performance of certain off-site engineering and preparatory work under the EPC contract at the Sabine Pass LNG receiving terminal site. In early April 2005, Bechtel accepted the NTP and commenced work under the EPC contract.

In April 2005, because Bechtel had accepted the NTP, additional advance capacity reservation fee payments of $10,000,000 and $5,000,000 were paid by Total and Chevron USA, respectively, to Sabine Pass LNG.

On April 13, 2005, FERC issued an order authorizing Corpus Christi LNG to construct and operate the Corpus Christi LNG receiving terminal, subject to specified conditions that must be satisfied prior to commencement of construction.

On April 22, 2005, we issued 26,789,242 shares of our common stock in a two-for-one stock split. The stock split entitled all stockholders of record at the close of business on April 8, 2005 to receive one additional share of common stock for each share held on that date.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 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 March 2004, the Dow Chemical Company (“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 beginning with commercial start-up of the facility expected to occur in 2008.

In July 2004, ConocoPhillips Company, (“ConocoPhillips”) and Freeport LNG entered into a long-term TUA under which ConocoPhillips has reserved 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 fee of $10 million from ConocoPhillips in January 2004. ConocoPhillips has also paid Freeport LNG an additional non-refundable $3.5 million to secure an option on 500 MMcf/d of additional capacity in the event that the terminal is expanded.

Sabine Pass LNG is developing an LNG receiving terminal with an initial regasification capacity of 2.6 Bcf/d, and we are currently evaluating the possibility of expanding such capacity. In March 2005, FERC issued an order authorizing Sabine Pass LNG to commence construction of the Sabine Pass LNG facility. In order to complete certain phases of the project, Sabine Pass LNG will be required to satisfy conditions specified by FERC. The NTP was accepted by Bechtel in early April 2005, and we expect to commence terminal operations in 2008.

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.

The TUA provides for Total to pay a fee of $0.32 per million British thermal units (“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 2009, subject to substantial completion. In addition, 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 Bechtel has accepted the NTP, an additional advance capacity reservation fee payment of $10 million was paid by Total to Sabine Pass LNG in April 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 a 20-year period beginning not later than July 2009, subject to substantial completion. Chevron USA has the option, at the same fee, either to reduce its reserved capacity at the Sabine Pass LNG facility 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 Corporation 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 $17 million has been paid through April 2005. An additional $3 million advance capacity reservation fee payment will be due if Chevron USA exercises its option to increase its capacity at the Sabine Pass LNG facility to approximately 1.0 Bcf/d by December 1, 2005.

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. In December 2004, we entered into a lump-sum turnkey agreement with Bechtel at a price of $646.9 million, which price is subject to change. 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 the Sabine Pass Credit Facility, which will be used to fund a substantial majority of the costs of constructing and placing into operation the Sabine Pass LNG receiving terminal.

We own 100% of the general partner and limited partner interests in Corpus Christi LNG, which is developing an LNG receiving terminal near Corpus Christi, Texas with a regasification capacity of 2.6 Bcf/d. We are currently marketing 1.0 Bcf/d of capacity under long-term TUAs of $0.32 per MMbtu, the same price contracted for the Sabine Pass LNG receiving terminal. We intend to realize the economic value of the remaining capacity under other long-term, mid-term and/or short-term arrangements. However, we may not be able to obtain any TUAs or other arrangements for the Corpus Christi LNG facility on terms acceptable to us at that price, or at all. In April 2005, FERC issued an order authorizing

Corpus Christi LNG to construct and operate the Corpus Christi LNG receiving terminal, subject to specified conditions that must be satisfied prior to commencement of construction. Construction is anticipated to begin by the end of 2005, with terminal operations commencing in 2008.

We own 100% of the general partner and limited partner interests in Creole Trail LNG. In November 2004, we announced the acquisition of options 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 the Creole Trail LNG facility in the same manner as our Sabine Pass LNG facility, although 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 the Sabine Pass LNG receiving terminal. We intend to realize the economic value of the remaining capacity under other long-term, mid-term and/or short-term arrangements. However, we may not be able to obtain any TUAs or other arrangements for the Creole Trail LNG facility 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.

In December 2003, we entered into an option agreement with J & S Cheniere (an entity in which we are a minority owner), 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 LNG facilities. We were paid $1 million in connection with the execution of the option agreement by J & S Cheniere in January 2004. The terms of the TUA contemplated by the J & S Cheniere option agreement have not been negotiated or finalized. We anticipate that definitive arrangements with J & S Cheniere may involve different terms and transaction structures than were contemplated when the option agreement was entered into in December 2003.

As part of our overall energy business strategy, we are pursuing other energy business initiatives, including downstream opportunities such as natural gas pipelines and storage, marketing and trading, as well as 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, any of which may include acquisitions, dispositions, investments and/or joint ventures.

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 currently estimate that, in the aggregate, our four terminal projects will require in excess of $3 billion, before financing costs, 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.

In January 2004, we initiated the marketing of regasification capacity for our proposed Sabine Pass and Corpus Christi LNG receiving terminals. We are currently engaged in the marketing process, 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. Certain of our TUAs are designed to serve as collateral to facilitate project level debt financing that we have obtained or may in the future obtain with respect to the construction of the related LNG receiving terminal.

As of March 31, 2005, we had working capital of $273.7 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.

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. 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, has reserved approximately 1.0 Bcf/d of LNG regasification capacity at the terminal and has paid $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 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.

On February 25, 2005, Sabine Pass LNG entered into the $822 million Sabine Pass Credit Facility with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC serves as collateral agent. The Sabine Pass 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 Sabine Pass Credit Facility will be

available until no later than April 1, 2009, after which time any unutilized portion of the Sabine Pass Credit Facility will be permanently canceled. Before Sabine Pass LNG may make an initial borrowing under the Sabine Pass 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. As of March 31, 2005, there were no borrowings outstanding under the Sabine Pass Credit Facility.

Borrowings under the Sabine Pass 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 Sabine Pass Credit Facility. The Sabine Pass Credit Facility provides for a commitment fee of 0.50% per annum on the daily committed, undrawn portion of the facility. Administrative fees must also be paid annually to the administrative agent and the collateral agent. Principal and interest payments are to be made in semi-annual installments commencing six months after the latter 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 Sabine Pass Credit Facility must commence no later than October 1, 2009, and all obligations under the Sabine Pass Credit Facility mature and must be fully repaid by February 25, 2015.

In connection with the closing of the Sabine Pass 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 Sabine Pass 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 Sabine Pass Credit Facility with respect to hedged drawings under the Sabine Pass 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 the EPC contract 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, an 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 contract. In late March 2005, we advanced 5% of the contract price, or $32.3 million, to Bechtel and issued the NTP. In early April 2005, Bechtel accepted the NTP and commenced all other aspects of the work under the EPC contract.

Sabine Pass LNG entered into the EPC contract with Bechtel for $646.9 million plus certain reimbursable costs. 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.

In November 2004, Total 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. Bechtel has accepted the NTP and, as a result, an additional advance capacity reservation fee payment of $10 million was paid by Total to Sabine Pass LNG in April 2005. 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.

An omnibus agreement with Chevron USA requires that it 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 was paid by Chevron USA to Sabine Pass LNG in April 2005 upon Bechtel’s acceptance of the NTP. 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. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’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 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.

We currently estimate that the cost of constructing the Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs. 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 we have since funded, or will arrange 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 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.

We currently estimate that the cost of constructing the Creole Trail LNG facility will be approximately $850 million to $950 million, before financing costs. 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 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.

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:

Net cash used in operations totaled $2.6 million in the first quarter of 2005 compared to $4.3 million in the first quarter of 2004.

Net cash used in investing activities was $44.0 million in the first quarter of 2005 compared to net cash provided by investing activities of $2.2 million in the first quarter of 2004. During the first quarter of 2005, we advanced $32.3 million to Bechtel related to the construction of our Sabine Pass LNG receiving terminal. We also charged $6.5 million to construction–in–progress related to the facility. The remaining first quarter 2005 cash used for investing activities primarily related to transfers to Sabine Pass LNG restricted cash collateral accounts under the Sabine Pass Credit Facility, purchase of fixed assets, advances to Freeport LNG and oil and gas property additions. The first quarter 2004 cash provided by investing activities of $2.2 million included a reimbursement from limited partnership investment and sales of our interests in oil and gas prospects, partially offset by oil and gas property and fixed asset additions.

Net cash used in financing activities was $15.0 million in the first quarter of 2005 compared to net cash provided by financing activities of $15.5 million in the first quarter of 2004. During the first quarter of 2005, we incurred $16.6 million in debt issuance costs related to the Sabine Pass Credit Facility and a contemplated private debt offering, partially offset by $1.6 million in proceeds from the exercise of stock options and warrants. During the first quarter of 2004, we received net proceeds of $15.3 million (after offering costs of $965,000) related to a private sale of our common stock in January 2004 and exercises of warrants and stock options during the quarter. We also received $1.2 million in partnership contributions in the first quarter of 2004 from the minority owner in Corpus Christi LNG. Cash flows from financing activities in the first quarter of 2004 were partially offset by the repayment of a $1.0 million note payable.

Due to the factors described above, our working capital decreased to $273.7 million as of March 31, 2005 compared to $305.8 million at December 31, 2004.

In February 2005, our stockholders approved an increase in Cheniere’s authorized common stock from 40 million to 120 million shares. On April 22, 2005, we issued 26,789,242 shares of our common stock in a two-for-one stock split. The stock split entitled all stockholders of record at the close of business on April 8, 2005 to receive one additional share of common stock for each share held on that date. All per share amounts and outstanding and weighted share amounts included in this quarterly report on Form 10-Q have been restated to give effect to the two-for-one stock split.

On February 8, 2005, we acquired the 33.3% minority interest in Corpus Christi LNG through the acquisition of BPU in exchange for 2,000,000 restricted shares of our common stock valued at $77.1 million plus direct transaction costs.

During the first quarter of 2005, a total of 259,902 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $1.1 million. A total of 400,000 shares of common stock were also issued pursuant to the exercise of warrants, resulting in net proceeds of $500,000.

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, thereby 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.

On March 30, 2005, we amended our office lease to increase our rentable square footage to include an additional floor on the premises. The lease term for the additional floor runs from May 2005 through January 2014. We have an option to renew the lease for an additional five years at the then-current market rate as part of the renewal of our original lease space. We have no monthly lease rental for the additional floor from May 2005 through April 14, 2007, after which time it ranges from approximately $30,000 to $39,000 per month through January 2014. We have prepaid $201,000 in rent related to 2013 and have included such amount in other assets on the accompanying consolidated balance sheet as of March 31, 2005.

The Sabine Pass Credit Facility established cash collateral accounts under the exclusive control of HSBC, the collateral agent. Accordingly, our total cash balance of $1.8 million held in these accounts as of March 31, 2005 is classified as restricted on our balance sheet.

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, respectively. 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 $6,000 of accrued interest is classified as restricted on our balance sheet at March 31, 2005.

As of March 31, 2005, 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.

Results of Operations—Comparison of the Three-Month Periods Ended March 31, 2005 and 2004

Our financial results for the three months ended March 31, 2005 reflect a net loss of $9.2 million, or $0.18 per share (basic and diluted), compared to a net loss of $1.1 million, or $0.03 per share (basic and diluted), for the three months ended March 31, 2004.

The major factors contributing to our net loss of $9.2 million during the first quarter of 2005 were LNG receiving terminal development expenses of $5.4 million and general and administrative expenses of $5.0 million. The major factors contributing to our net loss during the first quarter of 2004 were LNG receiving terminal development expenses of $4.4 million (which were offset by a $1.5 million minority interest in the operations of Corpus Christi LNG) and general and administrative expenses of $2.9 million. These 2004 expenses were offset by a $2.5 million reimbursement from our limited partnership investment in Freeport LNG and our equity share of the net income in Freeport LNG of $2.2 million.

LNG receiving terminal development expenses were 23% higher in the first quarter of 2005 ($5.4 million) than in the first quarter of 2004 ($4.4 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. Beginning in the first quarter of 2005, however, costs related to the construction of our Sabine Pass LNG receiving terminal have been capitalized. Our development expenses primarily include professional fees associated with front-end engineering and design work, obtaining orders from FERC authorizing construction of our facilities and other required permitting for the Sabine Pass LNG, Corpus Christi LNG and Creole Trail LNG receiving terminals and their related natural gas pipelines. Other expenses directly related to the development of our LNG receiving terminals, including expenses of our LNG employees directly involved in the development activities, are also included.

In the first quarter of 2005, we recorded $3.1 million in LNG receiving terminal development expenses related to the Creole Trail LNG receiving terminal and related pipeline. We incurred $654,000 in LNG receiving terminal development expenses in the first quarter of 2005 with respect to the Corpus Christi LNG receiving terminal and related pipeline. This amount was partially offset by $97,000 reimbursed by the 33.3% limited partner minority interest for the period prior to our February 2005 acquisition of such minority interest. In addition, we incurred $1.7 million in other LNG receiving terminal development expenses, including $1.0 million in LNG employee related costs. Our LNG staff increased from an average of 11 employees in the first quarter of 2004 to an average of 19 employees in the first quarter of 2005 as a result of the expansion of our business. LNG employee-related costs for the first quarter of 2005 also included non-cash compensation of $292,000 related to the amortization of deferred compensation associated with non-vested stock awarded in 2004.

In the first quarter of 2004, we incurred $1.9 million in terminal development expenses related to our Sabine Pass LNG receiving terminal. We also incurred $1.5 million related to our Corpus Christi LNG receiving terminal. This amount, however, was offset by 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. In addition, we incurred $1.0 million in terminal development expenses primarily related to LNG employee related costs. Such amount also included non-cash compensation of $525,000 (which included vested stock awards and amortization of deferred compensation associated with non-vested stock awards) related to Cheniere’s 2003 performance.

In the first quarter of 2005, our 30% equity share of the net loss of Freeport LNG was $844,000. In contrast, in the first quarter of 2004, our 30% equity share of the net income of Freeport LNG was $2.2 million because Freeport LNG recorded net income as a result of Freeport LNG’s receipt of a non-refundable fee of $10 million from ConocoPhillips in January 2004.

In January 2004, we received the final $2.5 million payment from Freeport LNG as provided under the terms of the agreement related to our February 2003 disposition of LNG assets in exchange for cash and a limited partnership interest in Freeport LNG. Because our investment basis in Freeport LNG had been previously reduced to zero, the $2.5 million payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations during the first quarter of 2004.

General and administrative (“G&A”) expenses primarily relate to our general corporate and other activities. These expenses increased $2.1 million, or 70%, to $5.0 million in the first quarter of 2005 compared to $2.9 million in the first quarter of 2004. The increase in G&A resulted primarily from the expansion of our business (including increases in average corporate staff from an average of 11 employees in the first quarter of 2004 to an average of 28 employees in the first quarter of 2005). Corporate employee-related costs for the first quarter of 2005 included non-cash compensation of $582,000 related to the amortization of deferred compensation associated with non-vested stock awarded in 2004. Corporate employee related costs for the first quarter of 2004 included non-cash compensation of $1.3 million (which included vested stock awards and amortization of deferred compensation associated with non-vested stock awards) related to Cheniere’s 2003 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 $284,000 in the first quarter of 2005 compared to $736,000 in the first quarter of 2004.

Depreciation, depletion and amortization (“DD&A”) expenses increased $322,000, or 156%, to $528,000 in the first quarter of 2005 from $206,000 in the first quarter of 2004. The increase primarily resulted from higher oil and gas DD&A as a result of an increase in our DD&A rate from $1.28 per thousand cubic feet equivalent (“Mcfe”) to $2.52 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 increased to $1.8 million in the first quarter of 2005 from $6,000 in the first quarter of 2004 primarily because of an increase in our cash and cash equivalents balances resulting from the $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.

Oil and gas revenues increased by $405,000, or 122%, to $737,000 in the first quarter of 2005 from $332,000 in the first quarter of 2004 as a result of a 133% increase in production volumes (135,000 Mcfe in the first quarter of 2005 compared with 58,000 Mcfe in the first quarter of 2004) partially offset by a 7% decrease in average natural gas prices to $5.39 per thousand cubic feet (“Mcf “) in the first quarter of

2005 from $5.77 per Mcf in the first quarter of 2004. Our production costs are relatively minor because most of our revenues are generated from non-cost bearing, overriding royalty interests (“ORRI”). In December 2004, we converted an ORRI to a cost-bearing working interest upon well payout resulting in higher production volumes as well as higher operating costs during the first quarter of 2005.

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 comply properly 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.

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 orders 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. Such costs will be amortized over the term of the lease should a lease be entered into. LNG terminal site rentals and related amortization of capitalized options are capitalized during the construction period of the terminal.

During the first quarter of 2005, we began capitalizing all direct costs associated with the construction of the Sabine Pass LNG facility, upon satisfaction of the following criteria: (1) regulatory approval had been received, (2) financing was in place and (3) management was committed to the construction of the facility. In addition, to the extent that we have future outstanding debt, we will capitalize interest on capital invested in the Sabine Pass LNG facility, as well as our other LNG receiving terminal projects during the construction period, in accordance with SFAS No. 34, Capitalization of Interest Cost, as amended by SFAS No. 58, Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34). Upon commencement of LNG terminal operations, capitalized interest, as a component of the total cost of the terminal, will be amortized over the estimated useful life of the LNG receiving terminal.

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

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.

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 properties. 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 SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires 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.

The process of estimating quantities of proved reserves is inherently uncertain, and our reserve data 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.

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.

As defined in SFAS No.133, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case the variability of floating interest rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the balance sheet prior to settlement), and any changes in the fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as a movement in interest rates, has been effectively fixed, so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement, or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, SFAS No. 133 requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. Any ineffective portion will be reflected in earnings.

Goodwill will be accounted for in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. Goodwill is subject to an annual goodwill impairment review, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate the carrying value may not be recoverable.

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 was scheduled to be effective for periods beginning after June 15, 2005. However, on April 14, 2005, the SEC deferred the effective date to January 1, 2006 for

companies with fiscal years ending December 31. Accordingly, we will be required to apply SFAS No. 123R beginning in the fiscal quarter ending March 31, 2006. We are currently assessing the provisions of SFAS No. 123R and its impact on our consolidated financial statements.

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 materially adversely affected.

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

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

We are utilizing interest rate swap agreements to mitigate exposure to fluctuations associated with our Sabine Pass Credit Facility. We do not use interest rate swap agreements for speculative or trading purposes.

The following tables summarize the fair market values of our existing interest rate swap agreements as of March 31, 2005 (dollars in thousands).

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We have been and may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of March 31, 2005, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.

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 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 10 million shares of common stock. We are cooperating fully with this SEC informal inquiry.

The stockholders also approved an amendment to our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 40,000,000 shares to 120,000,000 shares. A total of 36,670,774 shares of common stock voted for the amendment, 1,918,206 shares of common stock voted against the amendment and 175,484 shares of common stock abstained.

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CHENIERE ENERGY, INC.

/s/ Craig K. Townsend

Vice President and Chief Accounting Officer

(on behalf of the registrant and as principal

accounting officer)

Date: May 6, 2005


		Page
Part I. Financial Information

	Item 1. Consolidated Financial Statements
	Consolidated Balance Sheet	4
	Consolidated Statement of Operations	5
	Consolidated Statement of Stockholders’ Equity	6
	Consolidated Statement of Cash Flows	7
	Notes to Consolidated Financial Statements	8

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	33

	Item 4. Disclosure Controls and Procedures	34

Part II. Other Information

	Item 1. Legal Proceedings	34

	Item 4. Submission of Matters to a Vote of Security Holders	35

	Item 6. Exhibits	35


	March 31, 2005			December 31, 2004
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	246,848		$	308,443
Restricted Cash		1,760			—
Restricted Certificate of Deposit		904			900
Advances to EPC Contractor		32,347			—
Accounts Receivable		1,434			1,374
Prepaid Expenses		1,853			564

Total Current Assets		285,146			311,281

PROPERTY, PLANT AND EQUIPMENT, NET		28,859			20,880
DEBT ISSUANCE COSTS, NET		17,939			1,302
INVESTMENT IN LIMITED PARTNERSHIP		—			—
GOODWILL		76,924			—
INTANGIBLE LNG ASSETS		93			88
LONG-TERM DERIVATIVE ASSET		5,342			—
OTHER		217			16

Total Assets	$	414,520		$	333,567

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts Payable	$	2,584		$	1,262
Accrued Liabilities		7,673			3,196
Accrued Losses on Investment in Limited Partnership		780			1,071
Current Derivative Liability		361			—

Total Current Liabilities		11,398			5,529

DEFERRED REVENUE		23,000			23,000
LONG-TERM ASSET RETIREMENT OBLIGATION		100			99
MINORITY INTEREST		—			338
COMMITMENTS AND CONTINGENCIES		—			—

STOCKHOLDERS’ EQUITY
Preferred Stock, $.0001 par value Authorized: 5,000,000 shares Issued and Outstanding: none		—			—
Common Stock, $.003 par value Authorized: 120,000,000 shares at March 31, 2005 Issued and Outstanding: 53,578,484 shares at March 31, 2005 and 50,918,582 shares at December 31, 2004		161			153
Additional Paid-in-Capital		443,254			364,504
Deferred Compensation		(5,671	)		(6,543	)
Accumulated Deficit		(62,728	)		(53,513	)
Accumulated Other Comprehensive Income		5,006			—

Total Stockholders’ Equity		380,022			304,601

Total Liabilities and Stockholders’ Equity	$	414,520		$	333,567


	Three Months Ended March 31,
	2005			2004
Revenues
Oil and Gas Sales	$	737		$	332

Total Revenues		737			332

Operating Costs and Expenses
LNG Terminal Development Expenses		5,424			4,401
Production Costs		56			7
Depreciation, Depletion and Amortization		528			206
General and Administrative Expenses		4,990			2,936

Total Operating Costs and Expenses		10,998			7,550

Loss from Operations		(10,261	)		(7,218	)

Equity in Net (Loss) Income of Limited Partnership		(844	)		2,155
Reimbursement from Limited Partnership Investment		—			2,500
Interest Income and Other, Net		1,793			6

Loss Before Income Taxes and Minority Interest		(9,312	)		(2,557	)
Provision for Income Taxes		—			—

Loss Before Minority Interest		(9,312	)		(2,557	)
Minority Interest		97			1,482

Net Loss	$	(9,215	)	$	(1,075	)

Net Loss Per Share – Basic and Diluted	$	(0.18	)	$	(0.03	)

Weighted Average Number of Shares Outstanding – Basic and Diluted		52,364			36,219


	Common Stock			Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
	Shares	Amount		Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
Balance—December 31, 2004	50,919	$	153	$	364,504		$	(6,543	)	$	(53,513	)	$	—	$	304,601
Issuances of Stock	2,659		8		78,768			—			—			—		78,776
Other Comprehensive Income	—		—		—			—			—			5,006		5,006
Amortization of Deferred Compensation	—		—		—			872			—			—		872
Expenses Related to Offerings	—		—		(18	)		—			—			—		(18	)
Net Loss	—		—		—			—			(9,215	)		—		(9,215	)

Balance—March 31, 2005	53,578	$	161	$	443,254		$	(5,671	)	$	(62,728	)	$	5,006	$	380,022


	Three Months Ended March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(9,215	)	$	(1,075	)
Adjustments to Reconcile Net Loss to Net Cash Used In Operating Activities:
Depreciation, Depletion and Amortization		528			206
Non-Cash Compensation		874			1,826
Equity in Net (Income) Loss of Limited Partnership		844			(2,155	)
Reimbursement from Limited Partnership Investment		—			(2,500	)
Minority Interest		(97	)		(1,482	)
Other		22			33
Changes in Operating Assets and Liabilities:
Accounts Receivable – Affiliates		—			1,000
Other Accounts Receivable		(60	)		95
Prepaid Expenses		(1,290	)		(90	)
Accounts Payable and Accrued Liabilities		5,765			(162	)

NET CASH USED IN OPERATING ACTIVITIES		(2,629	)		(4,304	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Advance to EPC Contractor		(32,347	)		—
LNG Terminal Construction-In-Progress		(6,457	)		—
Investment In Restricted Cash		(1,760	)		—
Purchase of Fixed Assets		(1,424	)		(563	)
Investment in Limited Partnership		(1,134	)		—
Oil and Gas Property Additions		(594	)		(423	)
Acquisition Costs.		(149	)		—
Sale of Interest in Oil and Gas Properties		—			768
Reimbursement From Limited Partnership		—			2,500
Other		(145	)		(96	)

NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES		(44,010	)		2,186

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of Note Payable		—			(1,000	)
Sale of Common Stock		1,625			16,237
Debt Issuance Costs		(16,637	)		—
Offering Costs		(18	)		(965	)
Partnership Contributions by Minority Owner		74			1,178

NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(14,956	)		15,450

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(61,595	)		13,332

CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		308,443			1,258

CASH AND CASH EQUIVALENTS—END OF PERIOD	$	246,848		$	14,590

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	March 31, 2005			December 31, 2004
OIL AND GAS PROPERTIES, full cost method
Proved	$	3,384		$	3,339
Unproved		17,270			16,688
Accumulated depreciation, depletion and amortization		(1,311	)		(971	)

Total Oil and Gas Properties, net		19,343			19,056

LNG TERMINAL COSTS
LNG terminal construction-in-progress		6,457			—
LNG site and related costs, net		925			786

Total LNG Terminal Costs		7,382			786

FIXED ASSETS
Computers and office equipment		1,953			905
Furniture and fixtures		595			523
Other		597			434
Accumulated depreciation		(1,011	)		(824	)

Total Fixed Assets, net		2,134			1,038

PROPERTY, PLANT AND EQUIPMENT, net	$	28,859		$	20,880


	Interest Rate Derivative Instruments
Current derivative assets	$	—
Long-term derivative assets		5,342

Total derivative assets		5,342

Current derivative liabilities		361
Long-term derivative liabilities		—

Total derivative liabilities		361

Net derivative assets	$	4,981


Net derivative assets	$	4,981
Recognized derivative ineffectiveness recorded as a loss		25

Accumulated other comprehensive income.	$	5,006


	March 31, 2005		December 31, 2004
LNG Terminal construction	$	2,094	$	—
LNG terminal development expenses		2,565		1,611
Insurance expense		—		488
Professional and legal services		2,268		342
Taxes other than income		44		111
Other accrued liabilities		702		644

Accrued liabilities	$	7,673	$	3,196


	Three Months Ended March 31,
	2005			2004
Net Loss	$	(9,215	)	$	(1,075	)

Other Comprehensive Income Items:
Cash Flow Hedges		5,006			—

Other Comprehensive Income, net of tax		5,006			—

Comprehensive Loss	$	(4,209	)	$	(1,075	)


	Segments
	LNG Receiving Terminal Development			Oil & Gas Exploration and Development		Total			Corporate and Other(1)			Total Consolidated
	(in thousands)
As of or for the Three Months Ended March 31, 2005:
Revenues	$	—		$	737	$	737		$	—		$	737
Net income (loss)		(6,761	)		4		(6,757	)		(2,458	)		(9,215	)
Total assets		142,430			20,609		163,039			251,481			414,520

As of or for the Three Months Ended March 31, 2004:
Revenues	$	—		$	332	$	332		$	—		$	332
Net income (loss)		1,735			251		1,986			(3,061	)		(1,075	)
Total assets		3,455			20,200		23,655			16,219			39,874


Maturity Date	Notional Principal Amount		Fixed Interest Rate (Pay)		Weighted Average Interest Rate	Fair Market Value
July 25, 2005 through December 28, 2005	$	228,504	4.49	%	US $ LIBOR BBA	$	(139	)
December 28, 2005 through December 27, 2006		3,288,818	4.49	%	US $ LIBOR BBA		(168	)
December 27, 2006 through December 27, 2007		6,725,074	4.49	%	US $ LIBOR BBA		996
December 27, 2007 through December 29, 2008		8,301,316	4.49	%	US $ LIBOR BBA		2,148
December 29, 2008 through March 25, 2009		2,100,000	4.49	%	US $ LIBOR BBA		547
March 25, 2009 through March 25, 2010		1,390,700	4.98	%	US $ LIBOR BBA		(82	)
March 25, 2010 through March 25, 2011		1,352,000	4.98	%	US $ LIBOR BBA		858
March 25, 2011 through March 26, 2012		1,310,800	4.98	%	US $ LIBOR BBA		821

	$	24,697,212				$	4,981


3.1		Amendment No. 1 to Amended and Restated By-laws of the Company

10.1		Consent and Waiver No. 1 to Credit Agreement, dated as of April 4, 2005, among Sabine Pass LNG, L.P., Société Générale and HSBC Bank USA, National Association

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002