Form 10-Q for Period Ended September 30, 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 ¨.

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

As of October 31, 2005, there were 54,138,808 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,” “strategy” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this 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 in the United States 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 at the time such awards are granted. 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.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections – A Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 changes the requirements for accounting and reporting on a change in accounting principle, while carrying forward the guidance in APB Opinion No. 20, Accounting Changes and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, with respect to accounting for changes in estimates, changes in the reporting entity and the correction of errors. APB 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change, the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements for voluntary changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on the accounting change that occurs in a future period.

In October 2005, the FASB issued FASB Staff Position (“FSP”) 13-1, Accounting for Rental Costs Incurred During a Construction Period, to address the accounting for rental costs associated with operating leases that are incurred during a construction period. FSP 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. FSP 13-1 is effective in fiscal years beginning after December 15, 2005. As of September 30, 2005, we have capitalized $1,136,000 in rental expenses related to our Sabine Pass LNG terminal site lease.

We currently 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. There was no stock-based compensation expense associated with option grants recognized in the net income (loss) for the three and nine months ended September 30, 2005 and 2004, as all options granted had exercise prices greater than or equal to the market value of the underlying common stock on the dates of grant. The following table illustrates the effect on the net income (loss) and the net income (loss) per share if we had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation (in thousands, except per share data):

From our inception, we have recorded annual 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 stock-based employee compensation expense.

In February 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, the Sabine Pass LNG cash balance of $30,000 held in these accounts as of September 30, 2005 is classified as restricted on our balance sheet.

On August 31, 2005, Cheniere LNG Holdings, LLC, our wholly-owned subsidiary (“Cheniere LNG Holdings”), entered into a $600,000,000 Senior Secured Term Loan (the “Term Loan”) with Credit Suisse, Cayman Islands Branch (“Credit Suisse”) who also serves as collateral agent and administrative agent. Under the conditions of the Term Loan, Cheniere LNG Holdings was required to fund from the loan proceeds, a total of $216,200,000 into two collateral accounts: $181,000,000 into a debt service reserve collateral account and $35,200,000 into a capital contribution reserve collateral account. These funds are restricted to the payment of interest and principal due under the Term Loan, reimbursement of certain expenses, and funding of additional capital contributions to Sabine Pass LNG as required under the Sabine Pass Credit Facility. Because the accounts are controlled by the collateral agent, our cash and cash equivalent balance of $203,422,000 held in these accounts as of September 30, 2005 is classified as restricted on our consolidated balance sheet. Of this amount, $31,342,000 is classified as non-current due to the timing of certain required debt amortization payments and additional capital contributions required to fund the construction of the Sabine Pass LNG receiving terminal.

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 is 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 $1,123,000 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. The renewed letter of credit and the certificate of deposit both mature in November 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 consolidated balance sheet at September 30, 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 in March 2005 when the NTP was issued and that amount was classified on our consolidated balance sheet as a current asset. In accordance with the payment schedule included in the EPC contract, $2,696,000 per month is being reclassified to construction-in-progress over a twelve-month period. As of September 30, 2005, the remaining balance of the advance was $16,173,000.

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

As of September 30, 2005, we have capitalized $44,399,000 of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows:

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 and nine months ended September 30, 2004, our equity share of the net (loss) income of the limited partnership was $(583,000) and $85,000, respectively. Net income for the nine months ended September 30, 2004 was reduced by $278,000, which was our equity share of the net loss of the partnership not recorded in 2003 because our investment basis in the limited partnership at December 31, 2003 had been reduced to zero, and we had no obligation or intention to fund this unrecorded loss. For the three and nine months ended September 30, 2005, our equity share of the net loss of the limited partnership was $2,261,000 and $3,232,000, respectively. Our equity share of the Freeport LNG net loss for the three months ended September 30, 2005 includes $1,075,000 (“2005 Suspended Loss”) related to our 30% equity share of the second quarter 2005 net loss of the limited partnership. The 2005 Suspended Loss was not recognized as of June 30, 2005 because our investment in Freeport LNG had been reduced to zero, and we did not intend to fund the 2005 Suspended Loss at that time; however, we received additional capital call notices during the third quarter of 2005, as discussed below, which we intend to fund during the fourth quarter of 2005. As a result, we included the 2005 Suspended Loss as part of our 30% equity share of the third quarter 2005 net loss of Freeport LNG.

In January 2004, we received the final $2,500,000 payment from Freeport LNG pursuant to the terms of the agreement related to our February 2003 disposition of LNG assets in exchange for cash and a limited partner interest in Freeport LNG. Because our investment basis in Freeport LNG had been previously reduced to zero, the $2,500,000 payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations during the first quarter of 2004.

Through the first nine months of 2005, we have funded capital call notices totaling $1,592,000. As of September 30, 2005, we had outstanding capital call notices totaling $4,950,000 due during the fourth quarter of 2005. Of this amount, $225,000 was paid in October 2005. We presently intend to fund the remaining outstanding balance representing our 30% pro rata share, or $4,725,000.

As of September 30, 2005 and December 31, 2004, our investment balances in Freeport LNG were zero, and we had accrued losses on investment in limited partnership of $2,711,000 and $1,071,000, respectively. We accrued these liabilities because we intended to provide additional financial support through the capital calls as described above.

The financial position of Freeport LNG at September 30, 2005 and December 31, 2004, and the results of Freeport LNG’s operations for the three and nine months ended September 30, 2005 and 2004, are summarized as follows (in thousands):

In connection with the closing of the Sabine Pass Credit Facility in February 2005, we entered into interest rate swap agreements with HSBC and Société Générale (the “Sabine Swaps”) to hedge against changes in floating interest rates. Under the terms of the Sabine 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 Sabine Swaps have the effect of fixing the LIBOR component of the interest rate payable under the Sabine Pass Credit Facility with respect to anticipated hedged drawings thereunder 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 Sabine Swaps will be March 25, 2012.

In connection with the closing of the Term Loan on August 31, 2005, we entered into interest rate swap agreements with Credit Suisse (the “Term Loan Swaps”) to hedge against rising interest rates. Under the terms of the Term Loan Swaps, we hedged an initial notional amount of $600,000,000. The notional amounts decline in accordance with anticipated principal payments under the Term Loan. The Term Loan Swaps have the effect of fixing the LIBOR rate component of the interest rate payable under

the Term Loan at 3.75% from August 31, 2005 to September 27, 2007, at 3.98% from September 28, 2007 to September 27, 2008, and at 5.98% from September 28, 2008 to September 30, 2010. The final termination date of the Term Loan Swaps will be September 30, 2010.

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 Sabine Swaps and the Term Loan Swaps (collectively, 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 underlying debt to be highly effective. 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. For the three and nine months ended September 30, 2005, we have recognized net derivative gains of $931,000 and $264,000, respectively, into 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 September 30, 2005 for our derivative instruments (in thousands):

Below is a reconciliation of our net derivative liabilities to our accumulated other comprehensive loss at September 30, 2005 (in thousands):

For the three and nine months ended September 30, 2005, we have realized $42,000 of derivative 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. As of September 30, 2005, $4,600,000 of accumulated net deferred gains on the Swaps currently included in other comprehensive loss are expected to be reclassified to earnings during the next twelve months, assuming no change in the LIBOR forward curve at September 30, 2005. 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 three 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 interest in 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 $77,246,000, including direct transaction costs. Of this amount, $76,844,000 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. We perform an annual goodwill impairment review in the fourth quarter of each year, 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”), 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. Although non-refundable, 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, although 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 had the option, which it did not exercise, to reduce its capacity at Sabine Pass to approximately 500 MMcf/d by July 1, 2005. Chevron USA has the option 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, with $12,000,000 paid in 2004 and $5,000,000 paid 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, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

As of September 30, 2005 and December 31, 2004, we had recorded $38,000,000 and $23,000,000, respectively, 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.

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.

In February 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 interest of Corpus Christi LNG and are required to fund 100% of expenditures incurred after such date. We also manage the project as the general partner through one of our wholly-owned subsidiaries.

For the three months ended September 30, 2005 and 2004, the consolidated statement of operations includes zero and $417,000, respectively, related to the minority interest of Corpus Christi LNG. For the nine months ended September 30, 2005 and 2004, the consolidated statement of operations includes $97,000 and $2,650,000, respectively, related to the minority interest of Corpus Christi LNG.

As of September 30, 2005 and December 31, 2004, our long-term debt is comprised of the following (in thousands):

In February 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 $234,000,000 of the project costs. Of such amount, as of September 30, 2005, approximately $209,000,000 had been funded, and 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. Annual administrative fees must also be paid to the administrative and collateral agents. The principal of loans made under the Sabine Pass 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 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.

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 $700,000,000. 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 anticipated hedged drawings under the Sabine Pass Credit Facility, up to a maximum of $700,000,000 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.

During the construction period, all interest costs, including amortization of related debt issuance costs and commitment fees, will be capitalized as part of the total cost of the Sabine Pass LNG receiving terminal. As of September 30, 2005, $3,737,000 in commitment fees and amortization of debt issuance costs have been capitalized and included in LNG terminal construction-in-progress.

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 substantially all of Sabine Pass LNG’s property, including the Total and Chevron USA TUAs and the partnership interests in Sabine Pass LNG.

On July 27, 2005, we consummated a private offering of $325,000,000 aggregate principal amount of Convertible Senior Unsecured Notes due August 1, 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2.25% per year. The notes are convertible into our common stock under certain circumstances at an initial conversion rate of 28.2326 per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such a redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S. Treasury rate plus 50 basis points. The notes may be converted at the option of the holders at any time.

Concurrent with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread (consisting of a purchase and a sale of call options on our common stock) with an affiliate of the initial purchaser of the notes, having a term of two years, and a net cost to us of $75,703,000. These hedge transactions are expected to offset potential dilution from conversion of the notes up to a market price of $70.00 per share. The net cost of the hedge transactions is recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of the Emerging Issues Task Force (“EITF”) Issue 00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock. Net proceeds from the offering were $239,786,000, after deducting the cost of the hedge transactions, the underwriting discount and related fees. As of September 30, 2005, no holders have elected to convert their notes. Total interest expense recognized for the three and nine months ended September 30, 2005 was $1,567,000 before interest capitalization of $53,000.

On August 31, 2005, Cheniere LNG Holdings entered into the $600,000,000 Term Loan with Credit Suisse. The Term Loan interest rate equals LIBOR plus a 2.75% margin and terminates on August 30, 2012. In connection with the closing, Cheniere LNG Holdings entered into swap agreements with Credit Suisse to hedge the LIBOR interest rate component of the Term Loan. The blended rate of the swap agreements on the Term Loan results in an annual fixed interest rate of 7.25% (including the 2.75% margin) for the first five years (See Note 8 – Derivative Instruments). Beginning December 1, 2005, quarterly principal payments of $1,500,000 are required through June 30, 2012, and a final principal payment of $559,500,000 is required on August 30, 2012. As discussed in Note 2, a portion of the loan proceeds is controlled by Credit Suisse and is restricted to its use.

At September 30, 2005, principal repayments of $6,000,000 are due within the next 12 months and are classified on the balance sheet as a current liability. Interest expense for the three and nine months ended September 30, 2005 was $3,571,000 before interest capitalization of $27,000. The Term Loan contains customary affirmative and negative covenants. The obligations of Cheniere LNG Holdings are secured by its 100% equity interest in Sabine Pass LNG and its 30% limited partner equity interest in Freeport 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 income (loss) per share is computed by dividing the net income (loss) by the weighted average number of common shares outstanding for the period. The computation of diluted net income (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 reconciles basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 2005 and 2004 (in thousands):

We entered into an issuer call spread (an instrument that combines the purchase and sale of call options on our common stock), to offset the potential dilution from conversion of our Convertible Senior Secured Notes (described in Note 13 – “Long-Term Debt”). Purchased call options are always excluded from the calculation of diluted earning per share because they are anti-dilutive. SFAS No. 128, Earnings per Share, requires that we include the sold call options in the calculation of diluted earnings per share using the treasury stock method whenever the average market price of our common shares exceeds the strike price of the call options. The strike price of the sold call options is $70 per share, which is greater than the average market price of our common stock for the three and nine months ended September 30, 2005; thus, the sold call options were not included in the calculation of diluted earning per share. The total number of shares that could potentially be included under the sold call options is 9,176,000.

The following table is a reconciliation of our Net Income (Loss) to our Comprehensive Income (Loss) for the periods shown (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.

From time to time, officers and employees may charter aircraft for company business travel. We entered into a letter agreement (“charter letter”) with an unrelated third-party entity, Western Airways, Inc. (“Western”), that specifies the terms under which it would provide for charter of a Challenger 600 aircraft. One of the Challenger 600 aircraft which may be provided by Western for such services is owned by Bramblebush, LLC (the “LLC”). The LLC is owned and/or controlled by our Chairman and Chief Executive Officer, Charif Souki. Our Code of Business Conduct and Ethics prohibits potential conflicts of interest. Upon the recommendation of our Audit Committee, which determined that the terms of the charter letter are fair and in our best interest, our Board of Directors unanimously approved the terms of the charter letter in May 2005, and granted an exception under our Code of Business Conduct and Ethics in order to permit us to charter the Challenger 600 aircraft. For the three and nine months ended September 30, 2005, we incurred $233,000 and $485,000, respectively, related to the charter of the Challenger 600 aircraft owned by the LLC.

In January 2005, we exercised our Sabine Pass LNG site options and executed 30-year leases related to the option acreage. These lease agreements call for annual payments totaling $1,500,000. We have the option to renew these leases for six 10-year periods.

In March 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, there are no monthly lease payments for the additional floor from May 2005 through April 14, 2007, after which time the lease payments range 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 consolidated balance sheet as of September 30, 2005.

In July 2005, we executed a letter of intent with a potential EPC contractor to negotiate an EPC contract for construction of our Corpus Christi LNG terminal. Subject to certain terms and conditions, in the event that we did not execute an EPC contract with this contractor on or before January 31, 2006, we were obligated to pay the contractor a fee of $1,000,000. On October 10, 2005, we entered into a Memorandum of Understanding (“MOU”) with the same potential EPC contractor to negotiate the terms of an EPC contract for each of the Corpus Christi and Creole Trail LNG receiving terminals. Under the terms of the MOU, the $1,000,000 fee was cancelled and replaced by a $500,000 termination fee, payable, with certain exceptions, if we elect to terminate the MOU or if we fail to agree on the terms of an EPC contract for at least one of the terminals by April 30, 2007.

In October 2000, Cheniere and Warburg, Pincus Energy Partners, L.P. formed Gryphon Exploration Company (“Gryphon”) to fund an oil and gas exploration program in the Gulf of Mexico. Since January 1, 2003, our investment (effective 9.3% ownership) in Gryphon has been accounted for under the cost method of accounting, and our investment basis was zero. On August 31, 2005, Gryphon was sold for $283,000,000, plus assumption of $14,000,000 of net debt in a merger with Woodside Energy (USA). The transaction generated net cash proceeds of $20,206,000 to us, and since our investment balance was zero at the closing of this transaction, we recognized a gain on our consolidated statement of operations for the three and nine months ended September 30, 2005 equal to the net cash proceeds amount.

The following table provides supplemental disclosure of cash flow information (in thousands):

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. We use available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, Disclosures about Fair Value of Financial Instruments and does not impact our financial position, results of operations or cash flows.

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 development 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. In addition, our related natural gas pipeline development activities and other initiatives that complement the development of our LNG receiving terminal business are included in the segment.

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 (reversionary interests 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.

The following table summarizes our revenues, net income (loss) and total assets for each of our operating segments (in thousands):

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 completing our proposed 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 currently developing an LNG receiving terminal with initial 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. Construction began in the first quarter of 2005, and we expect that terminal operations will commence in 2008. In order to commence operations, Freeport LNG will be required to satisfy the remaining conditions specified by FERC. Freeport LNG has filed an application seeking an additional order from FERC to authorize the construction of an expansion.

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 approximately 500 MMcf/d of regasification capacity beginning with commercial start-up of the facility.

ConocoPhillips Company (“ConocoPhillips”) paid Freeport LNG nonrefundable fees of $13.5 million during 2004 and has reserved approximately 1.0 Bcf/d of regasification capacity in the terminal, has reserved 300 MMcf/d of additional regasification capacity in connection with the proposed expansion, has acquired a 50% interest in the general partner of Freeport LNG and has agreed to provide a substantial majority of the construction funding for the initial phase of the project. ConocoPhillips will be primarily responsible for managing the construction and operation of the facility.

We own 100% of the general partner and limited partner interests in Sabine Pass LNG, which is developing an LNG receiving terminal with an initial regasification capacity of 2.6 Bcf/d. In March 2005, FERC issued an order authorizing Sabine Pass LNG to commence construction of the Sabine Pass LNG facility. Construction began in March 2005, and we expect to commence terminal operations in 2008. In order to commence operations, Sabine Pass LNG will be required to satisfy remaining conditions specified by FERC. In July 2005, we made a filing with FERC seeking approval to increase the regasification capacity of the Sabine Pass LNG terminal to 4.0 Bcf/d.

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. An additional advance capacity reservation fee payment of $10 million was paid by Total to Sabine Pass LNG in April 2005.

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.

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. 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 had the option, which it did not exercise, to reduce its reserved capacity at the Sabine Pass LNG facility to approximately 500 MMcf/d by July 1, 2005. Chevron USA has the option to increase its reserved capacity to approximately 1.0 Bcf/d by December 1, 2005. Chevron Corporation will guarantee certain Chevron USA payment obligations under the TUA.

In accordance with the provisions of an omnibus agreement, Chevron USA agreed to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, under specified conditions, of which $17 million has been paid through September 30, 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 contract 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). Bechtel will be entitled to a bonus of $12 million, or a lesser amount in certain cases, if Bechtel, by April 3, 2008, 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 substained test period of 24 hours. Bechtel will be entitled to receive an additional bonus of up to $6 million if commercial operation is achieved by January 2, 2008. As of November 1, 2005, change orders to the EPC contract of $24.5 million in the aggregate have been approved, thereby increasing the total contract price to $671.4 million.

In August 2005, construction at our Sabine Pass LNG terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. In September 2005, the terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. No significant damage occurred to the site, equipment or materials by either of these hurricanes. We have begun remobilizing construction activities at the site and expect activity to return to pre-hurricane levels by mid-November 2005. Assessment of the impact from Hurricane Rita by us and our contractors and suppliers will continue, but we do not foresee any significant delay to the overall Sabine Pass construction plan. We expect that some of the down time may be recovered in the future.

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. In April 2005, FERC issued an order authorizing Corpus Christi LNG to site, construct and operate the Corpus Christi LNG receiving terminal. In order to obtain authorization to commence construction of the project, Corpus Christi LNG will be required to satisfy remaining conditions specified by FERC. We expect to begin construction after obtaining financing and customer commitments for regasification capacity and entering into an EPC agreement for our planned regasification capacity at our Corpus Christi LNG facility and to commence terminal operations approximately three years after construction commences.

We own 100% of the general partner and limited partner interests in 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. In May 2005, we filed on application with FERC to obtain an order to site, construct and operate the facility. Once we obtain FERC authorization, we expect to begin construction after obtaining financing and customer commitments for regasification capacity at Creole Trail LNG and to commence terminal operations approximately three years after construction commences.

We are currently marketing a total of 2.0 Bcf/d of regasification capacity at either of our Corpus Christi LNG and/or Creole Trail LNG receiving terminals under long-term TUAs at $0.32 per MMBtu, the same price contracted for at Sabine Pass LNG, to unaffiliated third parties; however, we may not be able to obtain any TUAs on terms acceptable to us, or at all. We currently intend that the remaining regasification capacity at these two facilities will be contracted to Cheniere LNG Trading & Marketing, Inc., our wholly-owned subsidiary, in order to utilize the regasification capacity as part of our LNG marketing activities.

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 January 2004 in connection with the execution of the option agreement by J & S Cheniere. The terms of the TUA contemplated by the 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 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.

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.

We are currently engaged in the marketing process, seeking long-term, creditworthy “anchor tenant” TUA contracts for a total of 2.0 Bcf/d of regasification capacity at either our proposed Corpus Christi LNG and/or Creole Trail LNG facilities. Upon execution of any TUA, we expect to receive an advance payment for regasification capacity sold. Any such advance payment would provide 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 September 30, 2005, our unrestricted cash and cash equivalent balance was $738.9 million. However, we must augment these existing sources of cash with significant additional funds in order to carry out our business plan.

We currently expect that capital requirements for our 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 currently planned 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 to $800 million, before financing costs. Construction began in the first quarter of 2005. ConocoPhillips has agreed to provide a substantial majority of the financing to construct the initial phase of the project. ConocoPhillips has also paid Freeport LNG an aggregate of $13.5 million, has reserved approximately 1.0 Bcf/d of LNG regasification capacity at the terminal and has reserved 300 MMcf/d of additional capacity in connection with the proposed expansion.

Freeport LNG has filed an application seeking an additional order from FERC to authorize the construction of an expansion that would increase the regasification capacity at its currently permitted 1.5 Bcf/d LNG terminal to approximately 4.0 Bcf/d. In addition to enhanced revaporization capacity, the proposed expansion includes a second dock, a third LNG storage tank and underground gas storage. 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, will change as a result of such an expansion.

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 with capital contributions by the limited partners. Capital contributions in the amount of approximately $1.6 million have been paid by us for our pro rata share during the first nine months of 2005. At September 30, 2005, we had outstanding approximately $5.0 million of capital call notices related to our 30% pro rata share, of which $225,000 was paid in October 2005. We intend to fund the remaining capital calls during the fourth quarter of 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 and funds raised through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

In February 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 $234 million of the project costs. Of such amount, as of September 30, 2005, approximately $209 million had been funded, and 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. Annual administrative fees must also be paid to the administrative and collateral agents. The principal of the loans made under the Sabine Pass 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 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.

Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass Credit Facility are secured by substantially all of Sabine Pass LNG’s property, including the Total and Chevron USA TUAs, and the partnership interests in Sabine Pass LNG.

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 anticipated 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 is providing Sabine Pass LNG with services for the engineering, procurement and construction of the Sabine Pass LNG receiving terminal. In December 2004, a limited notice to proceed (“LNTP”) was issued to and accepted by Bechtel, at which time Bechtel commenced 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 full notice to proceed, or NTP. This advance is credited against amounts due under the EPC contract in equal installments over a twelve-month period. In early April 2005, Bechtel accepted the NTP and commenced all other aspects of the work under the EPC contract.

The EPC contract with Bechtel is 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 in the event of 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, by April 3, 2008, 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. Bechtel will be entitled to receive an additional bonus of up to $6 million if commercial operation is achieved by January 2, 2008. As of November 1, 2005, change orders to the EPC contract of $24.5 million in the aggregate have been approved, thereby increasing the total contract price to $671.4 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. 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, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

In accordance with the provisions of an omnibus agreement, Chevron USA agreed to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20 million, under specified conditions, 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. 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 by December 1, 2005. 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, although 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. Although non-refundable, 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.

On July 27, 2005, we consummated a private offering of $325 million aggregate principal amount of Convertible Senior Unsecured Notes due August 1, 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2.25% per year. The notes are convertible into our common stock under certain circumstances at an initial conversion rate of 28.2326 per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume, weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such a redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S Treasury rate plus 50 basis points. The notes may be converted at the option of the holders at any time.

Concurrent with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread (consisting of a purchase and a sale of call options on our common stock) with an affiliate of the initial purchaser of the notes, having a term of two years and a net cost to us of $75.7 million. These hedge transactions are expected to offset potential dilution from conversion of the notes up to a market price of $70.00 per share. The net cost of the hedge transactions will be recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of EITF Issue 00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock. Net proceeds from the offering were $239.8 million, after deducting the cost of the hedge transactions, the underwriting discount and related fees.

We currently intend to use the net proceeds from the Convertible Senior Unsecured Notes offering primarily for the following purposes: (1) to fund the potential expansion of the Sabine Pass LNG receiving terminal, development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines; (2) to pay debt service obligations; and/or (3) for general corporate purposes.

On August 31, 2005, Cheniere LNG Holdings entered into the $600 million Term Loan with Credit Suisse. The Term Loan interest rate equals LIBOR plus a 2.75% margin and terminates on August 30, 2012. In connection with the closing, Cheniere LNG Holdings entered into swap agreements with Credit Suisse to hedge the LIBOR interest rate component of the Term Loan. The blended rate of the swap agreements on the Term Loan results in an annual fixed interest rate of 7.25% (including the 2.75% margin) for the first five years (See Note 8 – Derivative Instruments). Beginning December 31, 2005, quarterly principal payments of $1.5 million are required through June 30, 2012, and a final principal payment of $559.5 million is required on August 30, 2012. The Term Loan contains customary affirmative and negative covenants. The obligations of Cheniere LNG Holdings are secured by its 100% equity interest in Sabine Pass LNG and its 30% limited partner equity interest in Freeport LNG.

Under the conditions of the Term Loan, Cheniere LNG Holdings was required to fund from the loan proceeds a total of $216.2 million into two collateral accounts: $181 million into a debt service reserve collateral account and $35.2 million into a capital contribution reserve collateral account. These funds are restricted to the payment of interest and principal due under the Term Loan, reimbursement of certain expenses, and funding of additional capital contributions to Sabine Pass LNG required under the Sabine Pass Credit Facility. Because these accounts are controlled by Credit Suisse, the collateral agent, our cash and cash equivalent balance of $203.4 million held in these accounts as of September 30, 2005 is classified as restricted on our consolidated balance sheet. Of this amount, $31.3 million is classified as non-current due to the timing of certain required debt amortization payments and additional capital contributions required to fund the construction of the Sabine Pass LNG receiving terminal.

We currently intend to use the proceeds from the Term Loan primarily for the following purposes: (1) to fund our remaining equity requirements under the Sabine Pass Credit Facility for the construction of the Sabine Pass LNG receiving terminal; (2) to pay specified Term Loan debt service obligations and certain other expenses; (3) to pay fees and expenses related to the closing of the Term Loan; (4) to fund the potential expansion of the Sabine Pass LNG receiving terminal; (5) to fund the development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines; and/or (6) for general corporate purposes.

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 $9.1 million during the nine months ended September 30, 2005 compared to $16.7 million in the same period of 2004. The improvement resulted from $15.0 million of advance capacity reservation fee payments received by Sabine Pass LNG in 2005 which partially offsets $24.1 million of cash used in operating activities.

Net cash used in investing activities was $369.8 million during the nine months ended September 30, 2005 compared to net cash provided by investing activities of $1.7 million in the same period of 2004. During the first nine months of 2005, we funded $203.4 million related to restricted cash balances required under the Term Loan. We also advanced $16.2 million to the Sabine Pass LNG EPC contractor (net of $16.1 million credited against invoices and transferred to construction-in-progress related to the Sabine Pass LNG receiving terminal), and we charged $164.5 million to construction-in-progress related to the Sabine Pass LNG facility. The remaining cash used in investing activities during the first nine months of 2005 primarily related to the purchase of fixed assets, advances to Freeport LNG and oil and gas property additions. These uses of cash were partially offset by $20.2 million in proceeds received from the sale of our interest in Gryphon and $1.2 million from the sale of our interest in oil and gas prospects. During the first nine months of 2004, cash provided by investing activities of $1.7 million included a reimbursement from limited partnership investment, sale of limited partnership interest, and sales of our interests in oil and gas prospects, partially offset by the purchase of a restricted certificate of deposit and oil and gas property and fixed asset additions.

Net cash provided by financing activities was $809.4 million in the nine months ended September 30, 2005 compared to $20.8 million in the same period of 2004. During the first nine months of 2005, we received proceeds from the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan in the amounts of $249.3 million (net of $75.7 million for the issuer call spread) and $600.0 million, respectively. In addition, we received $2.1 million in proceeds from the exercise of stock options and warrants. These proceeds were partially offset by $42.0 million in debt issuance costs related to the Sabine Pass Credit Facility, the Convertible Senior Unsecured Notes and the Term Loan. During the first nine months of 2004, we received net proceeds of $19.1 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 first nine months of 2004. We also received $2.8 million in partnership contributions in the first nine months of 2004 from the minority owner in Corpus Christi LNG. Cash flows from financing activities in the first nine months of 2004 were partially offset by the repayment of a $1 million note payable.

Due to the factors described above, our cash and cash equivalents increased to $738.9 million as of September 30, 2005 compared to $308.4 million at December 31, 2004, and our working capital increased to $909.7 million as of September 30, 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.

In February 2005, we acquired the 33.3% minority interest in Corpus Christi LNG through the acquisition of BPU in exchange for two million restricted shares of our common stock valued at $77.0 million plus direct transaction costs.

During the first nine months of 2005, 15,000 shares of restricted common stock, valued at $498,000, were issued to employees who are not executive officers of Cheniere. As a result of these issuances, we recorded $498,000 of deferred compensation as a reduction to stockholders’ equity. The stock from each issuance vests 25% per year over a four-year period on each anniversary of the grant date.

During the nine months ended September 30, 2005, a total of 547,000 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $1.6 million. A total of 433,000 shares of common stock were also issued pursuant to the exercise of warrants, resulting in net cash proceeds of $520,000. In addition, 97,000 shares were issued in satisfaction of cashless exercises of warrants to purchase 100,000 shares of common stock, and 33,000 shares were issued in satisfaction of cashless exercises of options to purchase 34,000 shares of common stock.

In January 2005, we exercised our Sabine Pass site options and executed 30-year leases related to the option acreage. These lease agreements call for annual payments totaling $1.5 million. We have the option to renew these leases for six 10-year periods.

In March 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, there are no monthly lease payments for the additional floor from May 2005 through April 14, 2007, after which time the lease payments range 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 September 30, 2005.

The Sabine Pass Credit Facility established cash collateral accounts under the exclusive control of HSBC, the collateral agent. Accordingly, the Sabine Pass LNG cash balance of $30,000 held in these accounts as of September 30, 2005 is classified as restricted on our consolidated balance sheet.

In connection with completing the Term Loan, we established cash collateral accounts under the exclusive control of Credit Suisse, the collateral agent. Accordingly, our cash and cash equivalent balance of $203.4 million held in these accounts as of September 30, 2005 is classified as restricted on our consolidated balance sheet. Of this amount, $31.3 million is classified as non-current due to the timing of certain required debt service payments and additional contributions required for the construction of the Sabine Pass LNG receiving terminal.

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 is 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 $13,000 of accrued interest is classified as restricted on our consolidated balance sheet at September 30, 2005.

As of September 30, 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 September 30, 2005 and 2004

Our financial results for the three months ended September 30, 2005 reflected net income of $7.7 million, or $0.14 per share (basic and diluted), compared to a net loss of $5.6 million, or $0.15 per share (basic and diluted), for the three months ended September 30, 2004.

The major factor contributing to our net income of $7.7 million during the third quarter of 2005 was the $20.2 million gain on the sale of our investment in Gryphon, which was partially offset by LNG receiving terminal development expenses of $4.1 million and general and administrative expenses of $6.5 million. Absent the gain on the sale of our investment in Gryphon, we would have reported a net loss of $12.5 million, or $0.23 per share (basic and diluted), during the third quarter of 2005,. The major factors contributing to our $5.6 million net loss during the third quarter of 2004 were LNG receiving terminal development expenses of $3.4 million (which were offset by a $417,000 minority interest in the operations of Corpus Christi LNG), general and administrative expenses of $2.2 million and our equity share of the net loss of Freeport LNG of $583,000.

LNG receiving terminal development expenses were 20% higher in the third quarter of 2005 ($4.1 million) than in the third quarter of 2004 ($3.4 million). 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 our planned LNG receiving terminals, their related natural gas pipelines as well as other initiatives that complement the development of our LNG receiving terminal business. Expenses of our LNG employees involved in development activities are also included. Beginning in the first quarter of 2005, costs related to the construction of our Sabine Pass LNG receiving terminal have been capitalized.

In the third quarter of 2005, we recorded $1.5 million of LNG terminal development expenses attributable to our Creole Trail LNG and Corpus Christi LNG receiving terminals and the proposed Sabine Pass LNG expansion projects. In addition, we incurred $756,000 of development expenses relating to pipeline development activities for our Sabine Pass and Creole Trail LNG projects. We also incurred $1.8 million in other LNG receiving terminal development expenses, including $1.4 million in LNG employee-related costs. Our LNG staff increased from an average of 16 employees in the third quarter of 2004 to an average of 28 employees in the third quarter of 2005 as a result of the expansion of our business. LNG employee-related costs for the third quarter of 2005 included non-cash compensation of $296,000, primarily related to the amortization of deferred compensation associated with non-vested stock awarded in 2004.

In the third quarter of 2004, we incurred $1.5 million in terminal development expenses related to our Sabine Pass LNG receiving terminal and related pipeline. We also incurred $1.2 million related to our Corpus Christi LNG receiving terminal and related pipeline. This amount was offset partially by $417,000 related to the minority interest of our 33.3% limited partner. In addition, we incurred $734,000 in other terminal development expenses primarily related to LNG employee-related costs. Such amount included non-cash compensation of $112,000 related to the amortization of deferred compensation associated with non-vested stock awards granted in February 2004.

In the third quarter of 2005, our 30% equity share of the net loss of Freeport LNG was $2.3 million. In contrast, in the third quarter of 2004, our 30% equity share of the net loss of Freeport LNG was $583,000.

General and administrative (“G&A”) expenses primarily relate to our general corporate and other activities. These expenses increased $4.3 million, or 191%, to $6.5 million in the third quarter of 2005 compared to $2.2 million in the third quarter of 2004. The increase in G&A resulted primarily from the expansion of our business (including increases in corporate staff from an average of 14 employees in the third quarter of 2004 to an average of 55 employees in the third quarter of 2005). Corporate employee-related costs for the third quarter of 2005 and 2004 included non-cash compensation of $494,000 and $304,000, respectively, related to the amortization of deferred compensation associated with non-vested stock awards granted in 2004 and 2005. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $172,000 in the third quarter of 2005 compared to $197,000 in the third quarter of 2004.

Depreciation, depletion and amortization (“DD&A”) expenses increased $416,000, or 156%, to $682,000 in the third quarter of 2005 from $266,000 in the third 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 $1.18 per thousand cubic feet equivalent (“Mcfe”) in the third quarter of 2004 to $3.54 per Mcfe in the third quarter of 2005 and higher production volumes discussed below. DD&A also increased $261,000 in the third quarter of 2005 as a result of higher depreciation expense associated with the acquisition of furniture, fixtures and equipment and office space leasehold improvements associated with the expansion of our business.

During the third quarter of 2005, we recorded a net derivative gain of $931,000 attributable to the ineffective portion of our interest rate swaps.

Interest income increased to $4.5 million in the third quarter of 2005 from $32,000 in the third quarter of 2004 because cash and cash equivalents balances increased due to our common stock offering in December 2004 and the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan during the third quarter of 2005.

Interest expense, net of capitalization, was $5.1 million in the third quarter of 2005 compared to zero in the third quarter of 2004. This increase was attributable to the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan during the third quarter of 2005. Capitalized interest of $3.1 million in the third quarter of 2005 was primarily related to the amortization of debt issuance cost and commitment fees associated with the Sabine Pass Credit Facility.

Oil and gas revenues increased by $264,000, or 56%, to $729,000 in the third quarter of 2005 from $465,000 in the third quarter of 2004 as a result of a 15% increase in production volumes (92,000 Mcfe in the third quarter of 2005 compared to 80,000 Mcfe in the third quarter of 2004) and by a 37% increase in average natural gas prices to $7.87 per thousand cubic feet (“Mcf”) in the third quarter of 2005 from $5.73 per Mcf in the third 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, which resulted in higher production volumes as well as higher operating costs during the third quarter of 2005; however, production volumes from certain wells in the third quarter of 2005 were negatively impacted by the effects of Hurricanes Katrina and Rita.

Results of Operations — Comparison of the Nine-Month Periods Ended September 30, 2005 and 2004

Our financial results for the nine months ended September 30, 2005 reflected a net loss of $11.4 million, or $0.21 per share (basic and diluted), compared to a net loss of $14.8 million, or $0.39 per share (basic and diluted), for the nine months ended September 30, 2004.

The major factors contributing to our net loss of $11.4 million during the first nine months of 2005 were LNG receiving terminal development expenses of $14.9 million and general and administrative expenses of $17.1 million, which was significantly offset by the $20.2 million gain on the sale of our investment in Gryphon. Absent the gain on the sale of our investment in Gryphon, we would have reported a net loss of $31.6 million, or $0.59 per share (basic and diluted), for the first nine months of 2005. The major factors contributing to our $14.8 million net loss during the first nine months of 2004 were LNG receiving terminal development expenses of $13.4 million (which were offset by a $2.7 million minority interest in the operations of Corpus Christi LNG) and general and administrative expenses of $7.1 million, partially offset by a $2.5 million reimbursement from our limited partnership investment in Freeport LNG.

LNG receiving terminal development expenses were 11% higher in the first nine months of 2005 ($14.9 million) than in the first nine months of 2004 ($13.4 million). Beginning in the first quarter of 2005, however, costs related to the construction of our Sabine Pass LNG receiving terminal have been capitalized.

In the first nine months of 2005, we incurred $5.6 million in LNG pipeline development expenses primarily related to our Sabine Pass LNG and Creole Trail LNG projects. LNG receiving terminal development expenses for the first nine months of 2005 were $4.5 million and were mainly attributable to our Creole Trail LNG and Corpus Christi LNG terminal projects and the proposed Sabine Pass LNG terminal expansion. In addition, we incurred $4.8 million in other LNG receiving terminal development expenses, including $4.1 million in LNG employee-related costs. Our LNG staff increased from an average of 14 employees in the first nine months of 2004 to an average of 24 employees in the first nine months of 2005 as a result of the expansion of our business. LNG employee-related costs for the first nine months of 2005 included non-cash compensation of $874,000 related to the amortization of deferred compensation associated with non-vested stock awarded in 2004.

In the first nine months of 2004, we incurred $5.7 million in development expenses related to our Sabine Pass LNG receiving terminal and related pipeline. We also incurred $5.1 million related to our Corpus Christi LNG receiving terminal and related pipeline. This amount, however, was partially offset by the minority interest of our 33.3% limited partner totaling $2.7 million. Substantially all expenditures incurred through March 31, 2004 by Corpus Christi LNG 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. During the first nine months of 2004, we also incurred $2.6 million in LNG employee-related costs. Such amount included non-cash compensation of $750,000 (which included vested stock awards and amortization of deferred compensation associated with non-vested stock awards) granted in 2004.

In the first nine months of 2005, our 30% equity share of the net loss of Freeport LNG was $3.2 million. In contrast, in the first nine months of 2004, our 30% equity share of the net income of Freeport LNG was $85,000 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 pursuant to the terms of the agreement related to our February 2003 disposition of LNG assets in exchange for cash and a limited partner 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.

G&A expenses increased $10.0 million, or 141%, to $17.1 million in the first nine months of 2005 compared to $7.1 million in the first nine months of 2004. The increase in G&A resulted primarily from the expansion of our business (including increases in corporate staff from an average of 13 employees in the first nine months of 2004 to an average of 42 employees in the first nine months of 2005). Corporate employee-related costs for the first nine months of 2005 included non-cash compensation of $1.6 million related to the amortization of deferred compensation associated with non-vested stock awarded in 2004 and 2005. Corporate employee-related costs for the first nine months of 2004 included non-cash compensation of $2.0 million (which included vested stock awards and amortization of deferred compensation associated with non-vested stock awards) granted in 2004. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $644,000 in the first nine months of 2005 compared to $721,000 in the first nine months of 2004.

DD&A expenses increased $1.1 million, or 175%, to $1.7 million in the first nine months of 2005 from $632,000 in the first nine months of 2004. The increase resulted from higher oil and gas DD&A as a result of an increase in our DD&A rate from $1.24 per Mcfe for the first nine months of 2004 to $2.90 per Mcfe for the first nine months of 2005 and higher production volumes discussed below. DD&A also increased by $473,000 as a result of higher depreciation expense associated with the acquisition of furniture, fixtures and equipment and office space leasehold improvements associated with the expansion of our business.

During the first nine months of 2005, we recorded a net derivative gain of $264,000 attributable to the ineffective portion of our interest rate swaps.

Interest income increased to $8.1 million in the first nine months of 2005 from $48,000 in the first nine months of 2004 as a result of an increase in our cash and cash equivalent balances resulting from our common stock offering in December 2004 and the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan in the third quarter of 2005.

Interest expense, net of capitalization, was $5.1 million in the first nine months of 2005 compared to zero in the first nine months of 2004. This increase was attributable to the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan during the third quarter of 2005. Capitalized interest of $3.8 million in the first nine months of 2005 was primarily related to the amortization of debt issuance cost and commitment fees associated with the Sabine Pass Credit Facility.

Oil and gas revenues increased by $1.1 million, or 90%, to $2.2 million in the first nine months of 2005 from $1.1 million in the first nine months of 2004 as a result of a 68% increase in production volumes (327,000 Mcfe in the first nine months of 2005 compared with 194,000 Mcfe in the first nine months of 2004) and a 12% increase in average natural gas prices to $6.54 per Mcf in the first nine months of 2005 from $5.82 per Mcf in the first nine months of 2004. Our production costs are relatively minor because most of our revenues are generated from non-cost bearing 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 nine months 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 we believe that 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.

Costs to develop our planned LNG receiving terminals are expensed as incurred. 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 our planned 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. Beginning in 2006, however, such costs will be expensed as required by FSP 13-1.

In 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, during the construction periods of our LNG receiving terminal projects, we capitalize interest and other related debt costs 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 deferred initially.

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. At least annually, our reserves are estimated by an independent petroleum engineer.

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 thereby 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 is accounted for in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. We perform an annual goodwill impairment review in the fourth quarter of each year, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate that 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 at the time such awards are granted. 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.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections – A Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 changes the requirements for accounting and reporting on a change in accounting principle, while carrying forward the guidance in APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors. APB 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change, the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements for voluntary changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on the accounting change that occurs in a future period.

In October 2005, the FASB issued FSP 13-1, Accounting for Rental Costs Incurred During a Construction Period, to address the accounting for rental costs associated with operating leases that are incurred during a construction period. FSP 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. FSP 13-1 is effective in fiscal years beginning after December 15, 2005. As of September 30, 2005, we have capitalized $1.1 million in rental expenses related to our Sabine Pass LNG terminal site lease.

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 exposed to changes in interest rates, primarily as a result of our debt obligations. The fair value of our fixed rate debt is affected by changes in market rates. We utilize interest rate swap agreements to mitigate exposure to rising interest rates. We do not use interest rate swap agreements for speculative or trading purposes.

In connection with the closing of the Sabine Pass Credit Facility in February 2005, we entered into interest rate swap agreements to hedge against increases in floating interest rates with respect to draws, up to a maximum of $700 million under this facility. No debt was outstanding under this facility at September 30, 2005.

At September 30, 2005, we had $925 million of debt outstanding. Of this amount, our $325 million of Convertible Senior Unsecured Notes bore a fixed interest rate of 2.25%. The Term Loan, totaling $600 million, bore interest at floating rates; however, concurrent with the closing of the Term Loan, we entered into interest rate swaps with respect to this $600 million loan (See Note 8 -Derivative Instruments).

The following table summarizes the fair market values of our existing interest rate swap agreements as of September 30, 2005 (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 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 are and may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of September 30, 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.

As previously disclosed, we received a letter dated December 17, 2004 advising us of a nonpublic, informal inquiry being conducted by the SEC. On August 9, 2005, the SEC informed us that it had issued a formal order and commenced a nonpublic factual investigation of actions and communications by Cheniere, its current or former directors, officers and employees and other persons in connection with our agreements and negotiations with Chevron USA, the Company’s December 2004 public offering of common stock, and trading in our securities. The scope, focus and subject matter of the SEC investigation may change from time to time, and we may be unaware of matters under consideration by the SEC. We have cooperated fully with the SEC informal inquiry and intend to continue cooperating fully with the SEC in its investigation.

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: November 4, 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	25

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

	Item 4.	Disclosure Controls and Procedures	43

Part II. Other Information

	Item 1.	Legal Proceedings	44

	Item 6.	Exhibits	45


	September 30, 2005			December 31, 2004
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and Cash Equivalents	$	738,946		$	308,443
Restricted Cash and Cash Equivalents		172,110			—
Restricted Certificate of Deposit		912			900
Advances to EPC Contractor		16,173			—
Accounts Receivable		2,426			1,374
Derivative Assets		4,946			—
Prepaid Expenses		1,037			564

Total Current Assets		936,550			311,281

NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		31,342			—
PROPERTY, PLANT AND EQUIPMENT, NET		198,414			20,880
DEBT ISSUANCE COSTS, NET		44,399			1,302
INVESTMENT IN LIMITED PARTNERSHIP		—			—
GOODWILL		76,844			—
INTANGIBLE LNG ASSETS		93			88
OTHER		455			16

Total Assets	$	1,288,097		$	333,567

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts Payable	$	886		$	1,262
Accrued Liabilities		17,074			3,196
Accrued Losses on Investment in Limited Partnership		2,711			1,071
Current Portion of Long-Term Debt		6,000			—
Derivative Liabilities		139			—

Total Current Liabilities		26,810			5,529

LONG-TERM DEBT		919,000			—
DEFERRED REVENUE		38,000			23,000
LONG-TERM DERIVATIVE LIABILITIES		7,145			—
LONG-TERM ASSET RETIREMENT OBLIGATION		101			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 and 40,000,000 shares at September 30, 2005 and December 31, 2004, respectively
Issued and Outstanding: 54,043,808 shares at September 30, 2005 and 50,918,582 shares at December 31, 2004		162			153
Additional Paid-in-Capital		368,509			364,504
Deferred Compensation		(4,505	)		(6,543	)
Accumulated Deficit		(64,887	)		(53,513	)
Accumulated Other Comprehensive Loss		(2,238	)		—

Total Stockholders’ Equity		297,041			304,601

Total Liabilities and Stockholders’ Equity	$	1,288,097		$	333,567


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Revenues
Oil and Gas Sales	$	729		$	465		$	2,154		$	1,132

Total Revenues		729			465			2,154			1,132

Operating Costs and Expenses
LNG Receiving Terminal Development Expenses		4,127			3,447			14,902			13,415
Oil and Gas Production Costs		78			15			166			29
Depreciation, Depletion and Amortization		682			266			1,737			632
General and Administrative Expenses		6,523			2,242			17,114			7,106

Total Operating Costs and Expenses		11,410			5,970			33,919			21,182

Loss from Operations		(10,681	)		(5,505	)		(31,765	)		(20,050	)

Gain on Sale of Investment in Unconsolidated Affiliate		20,206			—			20,206			—
Equity in Net (Loss) Income of Limited Partnership		(2,261	)		(583	)		(3,232	)		85
Reimbursement from Limited Partnership Investment		—			—			—			2,500
Derivative Gain, net		931			—			264			—
Interest Expense		(5,058	)		—			(5,058	)		—
Interest Income		4,541			32			8,114			48

Income (Loss) Before Income Taxes and Minority Interest		7,678			(6,056	)		(11,471	)		(17,417	)
Provision for Income Taxes		—			—			—			—

Income (Loss) Before Minority Interest		7,678			(6,056	)		(11,471	)		(17,417	)
Minority Interest		—			417			97			2,650

Net Income (Loss)	$	7,678		$	(5,639	)	$	(11,374	)	$	(14,767	)

Net Income (Loss) Per Share
Basic	$	0.14		$	(0.15	)	$	(0.21	)	$	(0.39	)

Diluted	$	0.14		$	(0.15	)	$	(0.21	)	$	(0.39	)

Weighted Average Number of Shares Outstanding
Basic		53,938			38,546			53,358			37,536

Diluted		55,749			38,546			53,358			37,536


	Common Stock			Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Shares	Amount		Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
Balance—December 31, 2004	50,919	$	153	$	364,504		$	(6,543	)	$	(53,513	)	$	—		$	304,601
Issuances of Stock	3,110		9		79,237			—			—			—			79,246
Issuance of Restricted Stock	15		—		498			(498	)		—			—			—
Amortization of Deferred Compensation	—		—		—			2,536			—			—			2,536
Expenses Related to Offerings	—		—		(27	)		—			—			—			(27	)
Purchase of Issuer Call Spread	—		—		(75,703	)		—			—			—			(75,703	)
Comprehensive Loss on Interest Rate Swaps	—		—		—			—			—			(2,238	)		(2,238	)
Net Loss	—		—		—			—			(11,374	)		—			(11,374	)

Balance—September 30, 2005	54,044	$	162	$	368,509		$	(4,505	)	$	(64,887	)	$	(2,238	)	$	297,041


	Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(11,374	)	$	(14,767	)
Adjustments to Reconcile Net Loss to Net Cash Used In Operating Activities:
Depreciation, Depletion and Amortization		1,737			632
Non-Cash Compensation		2,487			2,699
Equity in Net (Income) Loss of Limited Partnership		3,232			(85	)
Gain on Sale of Investment in Unconsolidated Affiliate		(20,206	)		—
Reimbursement from Limited Partnership Investment		—			(2,500	)
Minority Interest		(97	)		(2,650	)
Non-Cash Derivative Gain		(282	)		—
Other		892			(21	)
Changes in Operating Assets and Liabilities:
Accounts Receivable – Affiliates		—			1,000
Other Accounts Receivable		(604	)		(314	)
Prepaid Expenses		(473	)		127
Deferred Revenue		15,000			—
Accounts Payable and Accrued Liabilities		589			(782	)

NET CASH USED IN OPERATING ACTIVITIES		(9,099	)		(16,661	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Restricted Cash and Cash Equivalents		(203,452	)		—
LNG Terminal Construction-In-Progress		(164,541	)		—
Advance to EPC Contractor, net of transfers to Construction-In-Progress		(16,173	)		—
Purchase of Fixed Assets		(2,806	)		(881	)
Investment in Limited Partnership		(1,592	)		—
Oil and Gas Property Additions		(1,982	)		(1,124	)
Acquisition Costs		(111	)		—
Proceeds from Sale of Investment in Unconsolidated Affiliate		20,206			—
Purchase of Restricted Certificate of Deposit		—			(1,123	)
Reimbursement from Limited Partnership Investment		—			2,500
Sale of Limited Partnership Interest.		—			883
Sale of Interest in Oil and Gas Prospects		1,235			1,632
Other		(602	)		(205	)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(369,818	)		1,682

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Convertible Senior Unsecured Notes		325,000			—
Proceeds from Term Loan		600,000			—
Purchase of Issuer Call Spread		(75,703	)		—
Debt Issuance Costs		(42,019	)		(108	)
Sale of Common Stock		2,095			20,102
Offering Costs		(27	)		(965	)
Repayment of Note Payable		—			(1,000	)
Partnership Contributions by Minority Owner		74			2,819

NET CASH PROVIDED BY FINANCING ACTIVITIES		809,420			20,848

NET INCREASE IN CASH AND CASH EQUIVALENTS		430,503			5,869

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

CASH AND CASH EQUIVALENTS — END OF PERIOD	$	738,946		$	7,127


	September 30, 2005			December 31, 2004
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	173,609		$	—
LNG site and related costs, net		939			786

Total LNG Terminal Costs		174,548			786

OIL AND GAS PROPERTIES, full cost method
Proved		3,480			3,339
Unproved		17,934			16,688
Accumulated depreciation, depletion and amortization		(1,919	)		(971	)

Total Oil and Gas Properties, net		19,495			19,056

FIXED ASSETS
Computers and office equipment		3,018			905
Furniture and fixtures		627			523
Computer software		1,068			334
Leasehold improvements		1,242			100
Other		26			—
Accumulated depreciation		(1,610	)		(824	)

Total Fixed Assets, net		4,371			1,038

PROPERTY, PLANT AND EQUIPMENT, net	$	198,414		$	20,880


Debt Facility	Debt Issuance Costs		Amortization Period ⁽¹⁾	Accumulated Amortization			Net Costs
Sabine Pass Credit Facility ⁽²⁾	$	20,176,000	10 years	$	(1,175,000	)	$	19,001,000
Convertible Senior Unsecured Notes ⁽³⁾		9,511,000	7 years		(246,000	)		9,265,000
Term Loan ⁽⁴⁾		16,083,000	7 years		(186,000	)		15,897,000
Other		236,000	—		—			236,000

	$	46,006,000		$	(1,607,000	)	$	44,399,000


	September 30, 2005			December 31, 2004
Current assets	$	4,541		$	38,106
Construction-in-progress		177,632			9,728
Fixed assets, net, and other assets		2,378			592

Total assets	$	184,551		$	48,426

Current liabilities	$	45,608		$	5,676
Note payable		147,693			48,041
Deferred revenue and other deferred credits		5,755			3,500
Partners’ capital		(14,505	)		(8,791	)

Total liabilities and partners’ capital	$	184,551		$	48,426


	Interest Rate Derivative Instruments
Current derivative assets	$	4,946
Derivative receivables ⁽¹⁾		410
Long-term derivative assets		—

Total derivative assets		5,356

Current derivative liabilities		139
Derivative payables ⁽²⁾		24
Long-term derivative liabilities		7,145

Total derivative liabilities		7,308

Net derivative liabilities	$	1,952


Net derivative liabilities	$	(1,952	)
Recognized derivative ineffectiveness recorded as a gain, net		(286	)

Accumulated other comprehensive loss.	$	(2,238	)


	September 30, 2005		December 31, 2004
LNG terminal construction costs	$	7,886	$	—
Debt issuance costs		3,152		—
LNG terminal development expenses		1,397		1,611
Insurance expense		—		488
Professional and legal services		894		342
Fixed assets		1,108		—
Taxes other than income		35		111
Accrued interest expense		1,436		—
Other accrued liabilities		1,166		644

Accrued liabilities	$	17,074	$	3,196


	September 30, 2005			December 31, 2004
Sabine Pass Credit Facility	$	—		$	—
Convertible Senior Unsecured Notes		325,000			—
Term Loan		600,000			—

		925,000			—
Less: Current Portion – Term Loan		(6,000	)		—

Total Long-Term Debt	$	919,000		$	—


	September 30, 2005
	Carrying Amount		Estimated Fair Value
Term Loan due 2012 ⁽¹⁾	$	600,000	$	600,000
2.25% Convertible Senior Unsecured Notes due 2012 ⁽²⁾		325,000		425,000
Sabine Pass Credit Facility ⁽³⁾		—		—

	$	925,000	$	1,025,000


	September 30, 2005		December 31, 2004
Total Assets:
LNG Receiving Terminal	$	714,061	$	24,355
Oil & Gas Exploration and Development		19,791		19,931

Total		733,852		44,286
Corporate and Other ⁽¹⁾		554,245		289,281

Total Consolidated	$	1,288,097	$	333,567


Maturity Date	Notional Principal Amount		Fixed Interest Rate (Pay)		Weighted Average Interest Rate	Fair Market Value ⁽¹⁾
October 2005 through December 2005	$	159,554	4.49	%	US $ LIBOR BBA	$	(13	)
January 2005 through December 2006		5,673,818	3.75% - 4.49	%	US $ LIBOR BBA		4,914
January 2006 through December 2007		9,086,074	3.75% - 4.49	%	US $ LIBOR BBA		5,314
January 2007 through December 2008		10,638,516	3.98% - 5.98	%	US $ LIBOR BBA		1,553
January 2008 through December 2009		5,113,000	4.49% - 5.98	%	US $ LIBOR BBA		(7,050	)
January 2009 through December 2010		2,942,260	4.98% - 5.98	%	US $ LIBOR BBA		(5,584	)
January 2010 through December 2011		1,331,700	4.98	%	US $ LIBOR BBA		(1,005	)
January 2011 through December 2012		650,100	4.98	%	US $ LIBOR BBA		(467	)

	$	35,595,022				$	(2,338	)


10.1		Credit Agreement, dated August 31, 2005, among Cheniere LNG Holdings, LLC, the initial lenders named therein, and Credit Suisse, Cayman Islands Branch

10.2		Security Agreement, dated August 31, 2005, from Cheniere LNG Holdings, LLC to Credit Suisse, Cayman Islands Branch

10.3		Pledge Agreement, dated August 31, 2005, from Cheniere LNG-LP Interests, LLC to Credit Suisse, Cayman Islands Branch

10.4		Control Agreement, dated August 31, 2005, from Cheniere LNG Holdings, LLC, to Credit Suisse, Cayman Islands Branch, and The Bank of New York

10.5		Novation Confirmation (#9233022), dated September 6, 2005, among Credit Suisse First Boston International, Cheniere Energy, Inc. and Cheniere LNG Holdings, LLC

10.6		Novation Confirmation (#9233023), dated August 31, 2005, among Credit Suisse First Boston International, Cheniere Energy, Inc. and Cheniere LNG Holdings, LLC

10.7		Novation Confirmation (#9233025), dated August 31, 2005, among Credit Suisse First Boston International, Cheniere Energy, Inc. and Cheniere LNG Holdings, LLC

10.8		Novation Confirmation (#9233026), dated August 31, 2005, among Credit Suisse First Boston International, Cheniere Energy, Inc. and Cheniere LNG Holdings, LLC

10.9		Novation Confirmation (#9233027), dated August 31, 2005, among Credit Suisse First Boston International, Cheniere Energy, Inc. and Cheniere LNG Holdings, LLC

10.10		Consent and Waiver No. 5 to Credit Agreement, dated as of July 5, 2005, among Sabine Pass LNG, L.P., Société Générale and HSBC Bank USA, National Association

10.11		Consent and Waiver No. 6 to Credit Agreement, dated as of July 27, 2005, among Sabine Pass LNG, L.P., Société Générale and HSBC Bank USA, National Association

10.12		Consent and Waiver No. 7 to Credit Agreement, dated as of August 29, 2005, among Sabine Pass LNG, L.P., Société Générale and HSBC Bank USA, National Association

10.13		Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan

10.14		Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan

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